of the republic of namibia · 110. over-voltage protection 111. ancillary protection functions 112....

N$94.20 WINDHOEK - 9 October 2018 No. 6731

GOVERNMENT GAZETTEOF THE

REPUBLIC OF NAMIBIA

CONTENTSPage

GENERAL NOTICE

No. 561 Transmission Grid Code: Electricity Act, 2007 ..................................................................................... 1________________

General Notice

ELECTRICITY CONTROL BOARD

No. 561 2018

TRANSMISSION GRID CODE: ELECTRICITY ACT, 2007

Under section 3(4)(a) of the Electricity Act, 2007 (Act No. 4 of 2007) the Electricity Control Board, with the prior approval of the Minister, has made the Transmission Grid Code set out in the Schedule.

G. HINDACHAIRPERSONBY ORDER OF THE BOARD

SCHEDULE

ARRANGEMENT OF CODES

CHAPTER 1INTRODUCTORY PROVISIONS

1. Definitions2. Objectives 3. Application

2 Government Gazette 9 October 2018 6731

CHAPTER 2TRANSMISSION SYSTEM GOVERNANCE

PART 1TRANSMISSION GRID CODE ADMINISTRATIVE AUTHORITY AND CONSTITUTION OF

TRANSMISSION GRID CODE ADVISORY COMMITTEE

4. Administrative authority5. Establishment of Grid Code Advisory Committee6. Constitution of the GCAC7. Functioning of the GCAC8. Secretariat transmission and distribution grid codes

PART 2PROCEDURES FOR REGISTRATION OF GRID CODE PARTICIPANTS, GRID CODE

AMENDMENT OR EXEMPTION

9. Registration and deregistration of participants10. Transmission Grid Code amendment or exemption process11. Submissions to the GCAC12. Recommendation to Board

PART 3DISPUTE MEDIATION, RESOLUTION AND APPEAL MECHANISM

13. Dispute mediation, resolution and appeal mechanism14. Complaints about the operations of the GCAC15. Disputes about decisions of Board16. Disputes about decisions of Minister17. Complaints among customers and service providers18. Incident report 19. Non-conformance report20. Submission of disputes to Board

PART 4COMPLIANCE, CODE AUDITS, CONTRACTING AND VERSION CONTROL

21. Compliance22. Code audits23. Contracting24. Version control

CHAPTER 3TRANSMISSION SYSTEM NETWORK

PART 1TRANSMISSION SYSTEM CONNECTION PROCESS AND CONDITIONS

25. Applications for transmission system connections26. Connection conditions27. Generator connection conditions28. Protection29. Backup impedance30. Lossoffield


31. Pole slipping facility32. Trip to house load33. Unit transformer high voltage back-up earth fault protection34. High voltage breaker fail protection35. High voltage pole disagreement protection36. Unit switch onto standstill protection37. Ability of units to island38. Excitation system requirements39. Reactive capabilities40. Multiple unit tripping (MUT) risks41. Governing design requirements42. Governing system frequency variations43. High Frequency requirements for turbo-alternators44. Over-frequency conditions in range of 51.5 to 52 Hz (stage H1)45. Over-frequency conditions above 52 Hz (stage H2)46. High frequency requirements for hydro alternators47. Low frequency requirements for turbo-alternator units48. Low frequency in range of 48.5 to 48.0 Hz (stageL1)49. Low frequency in range of 48.0 to 47.5 Hz (stage L2)50. Low frequency below 47.5 Hz (stage L3)51. Low frequency requirements for hydro-alternator units52. Droop53. Dead band54. Thermal power stations restart after power station black-out55. Hydro and gas turbines restart after power station black-out56. Black starting57. External supply disturbance withstand capability58. On load tap changing for generating unit step-up transformers59. Emergency unit capabilities60. Facility for independent generator action61. Automatic under-frequency starting62. Testing and compliance monitoring63. Non-compliance suspected by the system operator64. Unitmodifications65. Equipment requirements66. Distributors and end-use customers67. Power factor68. Protection69. Fault levels70. Distributor or end-use customer network performance71. Delivered quality of supply of transmission company 72. Equipment requirements

PART 2TRANSMISSION SYSTEM TECHNICAL REQUIREMENTS

73. Transmission company technical design requirements74. Equipment design standards75. Clearances76. Current Transformer (CT) and Voltage Transformer (VT) ratios and cores77. Standard busbar arrangements and Security criteria78. Transmission Substation standard Busbar arrangements79. Use of bypasses80. Motorised isolators81. Earthing isolators


82. Busbar Protection Current Transformers (CT’s)83. Tele-control84. Transformer tap change85. Substation drawings86. Protection requirements87. Protection design standards for equipment (feeder protection: 220kV and above)88. Protection settings for equipment (feeder protection: 220kv and above)89. Automatic reclosing for equipment (feeder protection: 220kV and above)90. Automatic reclosing cycles (ARC) for equipment (feeder protection: 220kV and above)91. Single phase automatic reclosing92. Three phase automatic reclosing (fast ARC)93. Three phase automatic reclosing (slow ARC)94. Power swing blocking95. Design standard: equipment protection requirements (feeder protection: 132kV and below

at transmission company substations)96. Protection settings: equipment protection requirements (feeder protection: 132kV and

below at transmission company substations97. Automatic reclosing: equipment protection requirements (feeder protection: 132kV and

below at transmission company substations)98. Tele-protection requirements99. Transformer and reactor protection100. TransformerInverseDefiniteMinimumTimeEarthFault101. TransformerHV/MVInverseDefiniteMinimumTimeOver-Current102. Transformer HV/MV instantaneous Over-Current103. TransformerLV(tertiary)InverseDefiniteMinimumTimeinstantaneousOver-Current104. Transformer current differential protection105. Transformer high impedance restricted Earth Fault106. Transformer thermal overload107. Transmission system busbar protection108. Transmission system bus coupler and bus section protection109. Transmission system shunt capacitor protection110. Over-voltage protection111. Ancillary protection functions112. Breaker fail or bus trip113. Breaker pole discrepancy114. Breaker anti-pumping115. Pantograph isolator discrepancy116. Master relay117. System protection requirements (under-frequency load shedding)118. System protection requirements (out of step tripping)119. System Protection requirements (Under-voltage load shedding)120. System Protection requirements (Sub-synchronous resonance protection)121. System protection requirements (protection against near 50 Hz resonance)122. System Protection requirements (protection settings impact on network stability (dynamic

stability))123. Protection system performance monitoring124. Nomenclature

PART 3TRANSMISSION SYSTEM PLANNING AND DEVELOPMENT

125. Transmission system planning and development126. Planning process127. Identificationofneedfortransmissionsystemdevelopment128. Forecasting demand


129. Technical limits and targets for planning purposes130. Voltage limits and targets131. Other targets for planning purposes132. Transmission system lines133. Transformers134. Series capacitors135. Shunt reactive compensation136. Circuit breakers137. Secondary automatic reclosing cycle current during single-phase re-closing138. Reliability criteria for planning purposes139. Contingency criteria for planning purposes140. Integration of power stations141. Power stations of less than 1000 MW142. Power stations of more than 1000 MW143. Transient stability144. Busbar arrangements145. Information required146. Criteria for network investments147. Least economic cost criteria148. Cost reduction investments149. Statutory or strategic investments150. Development investigation reports151. Transmission system master plan152. Mitigation of network constraints153. Interfacing between participants154. Special customer requirements for increased reliability155. Network maintenance

CHAPTER 4TRANSMISSION SYSTEM OPERATIONS

PART 1OPERATIONAL RELATIONS, PROCEDURES, PLANNING, CONDITIONS

AND CONTROL

156. Operation of interconnected power system157. System operator obligations158. System reliability and safety159. System security160. Operational measures161. Scheduling of generation and ancillary services162. Ancillary services163. Operating reserves164. Spinning reserve165. Quick reserve 166. Regulating reserve167. Black start and islanding168. Reactive power compensation and voltage control from units169. Regulation and load following170. Technical requirements of regulation and load following171. Near 50 Hz resonance control service172. Operational authority173. Operating procedures174. Operational liaison, permission for synchronisation175. Emergency and contingency planning


176. System frequency and ACE control under abnormal frequency or imbalance conditions177. Description of normal frequency or balancing conditions178. Operation during abnormal conditions179. Independent action by participants180. Voltage control181. Fault reporting and analysis or incident investigation182. Commissioning183. Risk of trip

PART 2MAINTENANCE COORDINATION OR OUTAGE PLANNING

AND TELE-CONTROL

184. Maintenance coordination or outage planning185. Roles and responsibilities of outage requester186. Roles and responsibilities of transmission company outage scheduler187. Roles and responsibilities of system operator outage scheduler188. Outage process189. Risk-related outages190. Maintenance planning between the transmission company and generators191. Refusal or cancellation of outages192. Communication of system conditions, operational information and interconnected power

system performance193. Tele-control

CHAPTER 5TRANSMISSION SYSTEM METERING

194. Principles of transmission metering195. Responsibility for metering installations196. Metering installation components197. Data validation198. Meterverification199. Metering database200. Testing of metering installations201. Metering data base inconsistencies202. Access to metering data203. Confidentiality

CHAPTER 6TRANSMISSION SYSTEM INFORMATION

EXCHANGE

PART 1INFORMATION EXCHANGE INTERFACE AND SYSTEM

PLANNING INFORMATION

204. Confidentialityofinformation205. Information exchange interface206. System planning information

PART 2OPERATIONAL INFORMATION

207. Pre-commissioning studies


208. Commissioningandnotification209. General information acquisition requirements210. Generating unit scheduling211. Energy market schedules212. Ancillary services market schedules213. File transfers214. Inter control centre communication215. Communication facilities requirements216. Information Exchange Tele control217. Telephone or facsimile218. Electronic mail219. Infrastructure at points of supply220. Access and Security221. Time standards222. Integrity of installation223. Data storage and archiving

PART 3POST-DISPATCH INFORMATION

223. Market information224. Generation settlement225. Ancillary services settlement226. Additional generating unit post-dispatch information227. Hourly demand metering data228. File transfers229. Performance data230. Generator performance data231. Distributor and end-use customer performance232. System performance information

CHAPTER 7TRANSMISSION SYSTEM RENEWABLE

ENERGY TECHNOLOGIES

233. Frequency response234. Voltage operating and regulation requirements235. Low voltage ride-through requirements236. Reactive power control237. Active power control238. Harmonic distortion requirements239. Unbalance requirements240. General protection and control requirements241. General telecommunication and Supervisory Control and Data Acquisition (SCADA)

requirements242. Power system studies and models243. Energised system testing

Annexure 1: Transmission Grid Code Amendment or Exemption Approval ProcessAnnexure 2: Contracting Framework for ParticipantsAnnexure 3: Generator Connection ConditionsAnnexure 4: Surveying, Monitoring and Testing for GeneratorsAnnexure 5: Voltage Tolerances for Various Frequency RangesAnnexure 6: Selection of Dead Line Charging End of the LineAnnexure7:SampleConfidentialityAgreementforInformationTransfertoThirdParties


Annexure 8: Distributor and End-Use Customer DataAnnexure 9: Generator Planning DataAnnexure 10: Generator Maintenance DataAnnexure 11: Operational DataAnnexure 12: Market Operational SchedulesAnnexure 13: Post-Dispatch InformationAnnexure 14: Generator Performance DataAnnexure 15: Planning Schedules

CHAPTER 1INTRODUCTORY PROVISIONS

Definitions

1. In this code a word or an expression to which a meaning has been given in the Act has that meaning and unless the context otherwise indicates -

“ancillary services” -

(a) means services supplied to the transmission company by generators, distributors or end-use customers -

(i) for the reliable and secure transport of power from generators to distributors and customers; and

(ii) to maintain the short-term reliability of the interconnected power system; and

(b) may include -

(i) the various types of reserves, black start and constrained generation;

(ii) operating reserves;

(iii) black start and islanding;

(iv) reactive power compensation and voltage control from units;

(v) regulation and load following; or

(vi) near 50Hz resonance control service.

“area control error” means the mismatch between the instantaneous demand and supply of a control area which combines the frequency error and the tie line schedule error;

“automatic generation control” means the automatic centralised closed loop control of generating units, by means of the computerised energy management system of the system operator, where unit output is controlled by changing the set point on the governor;

“auxiliary supply” means the supply of electricity to auxiliary systems of a unit or substation equipment;

“black start” means the provision of generating equipment that, following a total system collapse (black out), is able to -

(a) start without an outside electrical supply; and


(b) energiseadefinedportionofthetransmissionsystemsothatitcanactasastart-upsupplyfor other capacity to be synchronised as part of a process of re-energising the transmission system;

“busbar” means an electrical conduit at a substation where lines, transformers and other equipment are connected;

“co-generator”meansa unit that ispartofa specific industrialorproductionprocessand isnotconnected to the transmission system;

“constrained generation” means the difference between the energy scheduled at the point of connection of the generator under the unconstrained schedule, and the energy scheduled at the point of connection under the constrained schedule derived to accommodate transmission system constraints;

“control area” means a subset of SAPP that adheres to the minimum requirements for a control area as set out in the SAPP Operating Guidelines;

“control centre” means an entity responsible for the operational control of electricity network assets;

“customer” means a person that contracts directly with a transmission company for the provision of transmission services and may include a generator, distributor or end-use customer;

“distribution” means the conveyance of electricity to a customer through a distribution system which consists wholly or mainly of medium and low voltage networks;

“distribution system” means an electricity network consisting of assets -

(a) which may include substations, transformers, cables, lines and associated equipment; and

(b) which are operated at medium voltage and low voltage;

“distributor” means a licenced entity that owns, operates and maintains a distribution system;

“disputes” means unresolved complaints between parties that require intervention;

“embedded generator” means a unit, other than a co-generator, that is not directly connected to the transmission system;

“emergency” means a situation where transmission or distribution service-providers have an unplanned loss of facilities or another situation beyond their control that impairs or jeopardises their ability to supply their system demand;

“emergency outage” means an outage when plant has to be taken out of service so that repairs can immediately be affected to prevent further damage or loss;

“end-use customer” means users of electricity connected to the transmission system;

“firmsupply”meansasupplythatenjoysalevelofreliabilityasspecifiedincode139;

“flicker”meansacyclicvoltagefluctuation,normallybetween0,1Hzand10Hz,thatcausesopticalstress to humans;

“forced outage” means an outage that occurs when a component is taken out of service immediately, either automatically or as soon as switching operations can be performed as a direct result of abnormal operating conditions, emergency conditions or human error;


“frequency” means the number of oscillations per second on the AC waveform;

“GCAC” means the Grid Code Advisory Committee established in accordance with code 5(1)(a);

“generating unit” means a device used to produce electrical energy;

“generator” means a legal entity operating a licenced generating unit or power station;

“governing” means a mode of operation where any change in system frequency beyond the allowable frequency dead band will have an immediate effect on the unit output according to the governor droop characteristic;

“governor droop characteristic” means the MW or Hz characteristic according to which governing will take place;

“grid code” refers to any code made as a grid code under section 3(4) of the Act;

“Grid Code Advisory Committee” means a panel of stakeholder representatives constituted as contemplated in code 11 and tasked with the review of the grid code amendments;

“grid code participant” means a legal entity that falls under the mandate of the grid code and typical grid code participants include -

(a) licenced generators;

(b) licenced traders;

(c) licenced importer;

(d) licenced exporter;

(e) licenced transmitters who include wires businesses, supply businesses and metering administrators;

(f) licenced distributors;

(g) licenced suppliers; and

(h) end-customers who connect directly to the high voltage network;

“information” means knowledge that can be exchanged and always expressed by some type of data stored and processed either electronically or otherwise;

“information owner” means the party to whose system or installation the information pertains;

“interconnected power system” means the transmission system and any other connected system elements that are likely to have an impact on the electricity supply at a national level, including power stations with a capacity of more than 500 kVA and networks linking such power stations to the transmission system;

“interruptible load” means the consumer load or a combination of consumer loads that can be contractually interrupted without notice or reduced by remote control or on instruction from the system operator. Individual contracts place limitations on usage;


“interruptionofsupply”meansaninterruptionoftheflowofpowertoapointofsupplynotrequestedby the customer;

“imbalance” means the mismatch between the energy scheduled at a point of supply or a generator point of connection and the actual energy metered at that point of supply or generator point of connection over a scheduled period;

“islanding” means the capability of generating units to settle down at nominal speed, supplying own auxiliary load after separation from the grid, at up to full load pre-trip conditions;

“load following” means the provision of generation and load response capability, including capacity, energy, and manoeuvrability, that is dispatched by system operator to match power generation and load demand within a scheduling period;

“load reduction” means the ability to reduce customer demand by load curtailment and load shedding;

“losses” means the technical or resistive energy losses incurred on the transmission system;

“major incident” means an incident where -

(a) more than 20 system minutes of load was interrupted; or

(b) severe damage to the plant has occurred.

“manual load shedding” means the load reduction obtained by manually shedding load at convenient points on the distribution system within 10 minutes of the instruction being issued by the system operator;

“maximum continuous rating” means the capacity that a generating unit is rated to produce continuously under normal conditions;

“metering” means all the equipment employed in measuring the supply together with the apparatus directly associated with it;

“metering installation” means all meters, fittings, equipment, wiring and installations used formeasuringtheflowofelectricity;

“participant” includes -

(a) a generator with a power station where the total installed generating capacity is greater than 10 MVA;

(b) generators with power stations connected to any transmission system;

(c) generators embedded in any distribution system connected to any transmission system;

(d) generators providing ancillary services for system operation purposes;

(e) distributors connected to any transmission system;

(f) end-use customers connected to any transmission system, or their respective distributor acting on their behalf;

(g) a retailer or other wholesale market participant required to contract for the use of any transmission system;


(h) transmission companies;

(i) the system operator;

(j) other participants, in the ancillary services market, with interruptible loads; or

(k) the market operator;

“party” means any participant or the Board;

“planned interruption” a planned outage that will interrupt customer supply;

“planned outage” means an outage of equipment that is requested, negotiated, scheduled and confirmedaminimumof14dayspriortomaintenanceorrepairstakingplace;

“point of common coupling” means the electrical node, normally a busbar, in a transmission substation wheredifferentfeederstocustomersareconnectedtogetherforthefirsttime;

“point of connection” means the electrical node in a transmission substation where the assets of a customer are physically connected to the assets of a transmission company;

“point of supply” means a transmission substation where energy can be supplied to distributors and end-use customers;

“power station” means one or more units at the same physical location;

“power quality directive” means the Board directive for the management of power quality in the electricity supply industry;

“primary substation equipment” means high voltage equipment installed at substations;

“protection” means the process of clearing a fault on the interconnected power system in order to protect plant and people;

“quick reserve” means interruptible load or capacity readily available which can be started and loaded within 10 minutes to meet the system demand. This includes hydro plant, gas turbines, pumped storage and interruptible load;

“quote”meansalegaldocumentgiventoacustomerforthepurposeofprovidingapriceforspecifiedtransmission services;

“regulating reserve” means a reserve that is under automatic generation control and has the generation capacity or customer loads to respond within 10 seconds and be fully active within 10 minutes of activation;

“regulation” means the provision of generation and load response capability, including capacity, energy and manoeuvrability that responds to automatic control signals issued by the system operator;

“risk-related outage” means a planned outage where the next credible contingency would result in a loss of load, loss of supply, voltage slide, thermal overload or dynamic stability constraint;

“SAPP” means the Southern Africa Power Pool -

(a) founded in 1995 as a cooperation of national electricity companies in Southern Africa; and


(b) consisting of utilities of SADC member states;

“scheduling” means a process to determine which unit or equipment will be in operation and at what loading;

“security” means the probability of not having an unwanted operation;

“service provider” means any licenced transmission company;

“single buyer” means the entity responsible for administering the electric energy market and the ancillary services market including daily scheduling and settlement;

“speed of operation” means the time taken to clear a fault on the interconnected power system;

“spinning reserve” means the unused capacity which is synchronized to the system and which can be delivered immediately without manual intervention;

“stakeholders” means the entities affected by or having a material interest in the Transmission Grid Code including customers and other participants, the Board, the single buyer and the SAPP;

“substation” means a site at which switching or transformation equipment is installed;

“system frequency” means the frequency of the fundamental AC voltage as measured at selected points by the system operator;

“system minutes” means the normalised performance indicator for interruptions calculated as System Minutes interrupted = energy interrupted (MWh) * 60 / system peak demand (MW);

“system operator” means the entity responsible for short-term reliability of the interconnected power system, which is in charge of controlling and operating the transmission system and dispatching generation, or balancing the supply and demand, in real time;

“transmission” means the conveyance of electricity by means of a transmission system, which consists wholly or mainly of high voltage networks and electrical plant, from an energy source or system to a customer;

“transmission company” means an entity that holds a valid transmission licence and depending on the licence conditions may be responsible for -

(a) system operations;

(b) transmission supply business;

(c) transmission wires business;

(d) imports and exports; and

(e) single buyer;

“transmission company outage scheduler” means a person appointed by the transmission company to check for multiple requests for an outage of the same network unit;

“transmission equipment” means the equipment that is needed for the purpose of transmission;

“transmission metering administrator” means a licenced transmission company that is responsible for all transmission tariff metering installation, maintenance and operations;


“transmission supply business” means a licenced transmission company that is responsible for supplying energy to transmission customers;

“transmission network” means the electricity transmission network owned and operated by the transmission company.

“transmission system” means an electricity network consisting of assets including substations, transformers, cables, lines and associated equipment, which are operated wholly or mainly at a high voltage;

“transmission wires business” means a licenced transmission company that is responsible to install, operate and maintain transmission equipment; and

“unplanned outage”means an outage that is not requested, negotiated, scheduled and confirmed14 days before the outage takes place but does not include a forced outage, emergency outage or opportunity maintenance.

Objectives of Transmission Grid Code

2. (1) The objectives of the Transmission Grid Code are to -

(a) establish the rules and procedures that allow a person to use the power system;

(b) permitthepowersystemtobeplannedandoperatedsafely,reliably,efficientlyandeconomically;

(c) be objective, transparent, non-discriminatory and consistent with Government policy;

(d) provide for the overall administration and review of the various aspects of -

(i) the Transmission Grid Code; and

(ii) the Distribution Grid Code published in terms of section 3(4)(a) of the Act as the Transmission Grid Code must be read in conjunction with the relevant legislation, licences issued to generators, transmission companies and distributors, and other operating codes that relate to the Electricity Supply Industry;

(e) set the -

(i) connection conditions for generators, distributors and end-use customers; and

(ii) standards used to plan and develop the transmission system;

(f) set out the responsibilities and roles of the participants as far as the Interconnected PowerSystem(IPS)isconcernedandmorespecificallyissuesrelatedto-

(i) reliability, security and safety of the interconnected power system;

(ii) ancillary services;

(iii) market operation actions required by the system operator;


(iv) independent actions required and allowed by customers;

(v) operation of the interconnected power system under abnormal conditions; and

(vi) field operation, maintenance and maintenance coordination or outageplanning;

(f) ensure a metering standard for all current and future participants;

(g) specify metering requirements to be adhered to;

(h) clarify levels of responsibility relating to metering requirements contemplated in paragraph (g);

(i) definetheobligationsofparticipantswithregardtotheprovisionofinformationforthe implementation of the code.

(2) Informationexchangedbetweenpartiesgovernedbythecodeisconfidentialunlessotherwise stated.

(3) TheNRS057:2001meteringspecificationsmustbeusedasthemeteringrequirementsfor the Transmission Grid Code.

(4) Despitesubcode(3),theBoardmayoverridesomesectionsoftheNRSspecificationsshoulditfindtheminadequateordivergentfromChapter5.

(5) If an aspect is not fully or clearly addressed in the NRS 057:2001 metering specifications or if a conflict arises between the provisions of the code and the NRS 057:2001meteringspecifications,thecodetakesprecedenceovertheNRS057:2001meteringspecifications.

Application of Transmission Grid Code

3. (1) This Transmission Grid Code applies to all users of the transmission system including distributors, embedded generators, end-use customers, retailers, re-sellers and any other entities with equipment connected to the distribution system.

(2) The provisions of this Transmission Grid Code relating to the transmission system metering apply to all participants in respect of any metering point at the boundary of the transmission system.

CHAPTER 2TRANSMISSION SYSTEM GOVERNANCE

PART 1TRANSMISSION GRID CODE ADMINISTRATIVE AUTHORITY AND CONSTITUTION OF

TRANSMISSION GRID CODE ADVISORY COMMITTEE

Administrative authority

4. The Board is the administrative authority for the Transmission Grid Code and the Board must ensure that the Transmission Grid Code is compiled, approved and implemented for the benefitoftheelectricityindustry.


Establishment of Grid Code Advisory Committee

5. (1) The Board must -

(a) establish a Grid Code Advisory Committee; and

(b) ensure the proper functioning of the GCAC contemplated in paragraph (a).

(2) The GCAC is established to -

(a) ensure a consultative stakeholder process is followed in the formulation and review of the grid code;

(b) review and make recommendations regarding proposals to amend the grid code;

(c) review and make recommendations regarding proposals for exemption to comply with the grid code; and

(d) facilitate the provision of expert technical advice to the Board on matters related to the grid code.

Constitution of GCAC

6. (1) The GCAC is a stakeholder representative panel, representing participants.

(2) Members of the GCAC must ensure that they consult with their constituencies with respect to their role on the GCAC.

(3) The Board must annually review the composition of and constituencies represented bytheGCACtoensurethatitisatalltimesreflectiveoftheevolvingindustry.

(4) The Board may decide to expand the composition of the GCAC as part of the membership review process in consultation with the GCAC.

(5) The Board must ensure that members on the GCAC are able to make meaningful contributions towards the membership review process contemplated in subcode (4).

(6) The GCAC must consist of at least the following members:

(a) one member representing the system operator;

(b) one member representing transmission companies;

(c) two members representing generators;

(d) two members representing distributors;

(e) one member representing large end-use customers; and

(f) two Board members, one to chair and the other to assist the secretariat.

(7) Themembersmustbeidentifiedasfollows:

(a) if an industry association represents the larger part of the constituency, the association will be requested to make the nomination;


(b) if the constituency consists of more than one association or a relatively small number of entities, calls for nominations will be sent to all entities and the Board may -

(i) decide on the member if more than the required number of nominations are received; or

(ii) choose the member if no nominations are received; or

(c) ifthereisnoidentifiableentity,apubliccallfornominationwillbesentoutbytheBoard and the Board may decide on the member if more than the required number of nominations are received.

(8) The Board must publish changes in membership within 14 days, on the website of the Board.

(9) GCAC members must serve a three year term, after which they are eligible for reappointment.

(10) Despite subcode (9), the -

(a) constituency of a GCAC member may replace that member at any given time but a 14 days written notice must be given to the secretariat of the GCAC and to the Board before the replacement; or

(b) Board may, on the recommendation of the GCAC, request the constituency of a GCAC member to replace that member if that member has not attended three consecutive meetings.

(11) GCAC members must nominate an alternative representative and that nomination must be made in writing to the secretariat of the GCAC.

Functioning of GCAC

7. (1) The GCAC must review all proposals for amendment of or exemptions from the Transmission Grid Code.

(2) The GCAC must schedule at least one annual review session and the format of a session may be determined by the GCAC, but should include a work session if proposed changes are of a substantive nature.

(3) Agenda items for a session contemplated in subcode (2) must be circulated at least 14 days in advance of the session.

(4) The GCAC must -

(a) subject to code 6, determine its own meeting procedures and code of conduct; and

(b) publish the meeting procedures and code of conduct, contemplated in paragraph (a), on the website of the Board.

(5) A Board member must chair the GCAC meetings and if that Board member or his or her alternate is unable to attend the GCAC meeting that Board member or his or her alternate must make arrangements for an alternative chairperson for the duration of the meeting.


(6) A quorum at GCAC meetings consists of 50 percent of GCAC members plus one member of the Board, and the GCAC must take decisions by means of a majority vote of the GCAC members constituted as contemplated in code 6(6), and if votes are even then the Chairperson has the deciding vote.

(7) Alternate members must be allowed to vote only when the main member is not available for voting.

(8) If a quorum is not present within 30 minutes of the starting time for a GCAC meeting,asspecifiedbythesecretariatinawrittennoticeissuedtoGCACmembers,themembersatthe meeting must make the necessary recommendations to GCAC members and the secretariat must circulate the necessary recommendations electronically to all GCAC members for decision within a periodoffiveworkdays.

(9) On receipt of the recommendations contemplated in subcode (8), the GCAC members must, within the period contemplated in that subcode, make a decision and communicate the decision in writing to the secretariat.

(10) The decision contemplated in subcode (9) is effective only if voted on by a quorum.

(11) If a decision is voted on as contemplated in subcode (10), the decision must be minutedasconfirmedatthenextGCACmeetingwhereaquorumispresent.

(12) The secretariat must record all the decisions of the GCAC including the dissenting views expressed by GCAC members.

(13) The Board must fund the administrative activities of the GCAC but GCAC members are responsible for their own travel and subsistence expenditure.

(14) The GCAC may -

(a) co-opt experts with the purpose of allowing expert opinion to be obtained regarding complicated submissions;

(b) encourage industry participation and consultation in the activities of the experts contemplated in paragraph (a); or

(c) obtain industry participation and consultation through the activities of the experts contemplated in paragraph (a).

(15) The GCAC must provide the experts contemplated in code 14(a) with a full scope of work and an urgency indicator for each task referred to them.

(16) The Board must, in addition to its mandate under section 3(4)(a), publish the Transmission Grid Code or any amendments to the Transmission Grid Code, on its website.

Secretariat of transmission and distribution grid codes

8. (1) The system operator is appointed as the secretariat of the transmission and distribution grid codes subject to review by the Board and the secretariat is accountable to the Board and the GCAC for its activities.

(2) The functions of the secretariat are to -

(a) ensure procedures are developed and published for the review of proposed amendments and exemptions by the GCAC;


(b) provide standard submission forms to participants;

(c) assist, when requested, in the preparation of submissions to the GCAC;

(d) prepare amendment and exemption proposals for submission to the Board following review by the GCAC;

(e) manage grid code documentation;

(f) disseminate relevant information;

(g) inform participants of the progress with applications for amendment or exemption;

(h) co-ordinate the activities of the GCAC;

(i) keep and circulate minutes of meetings and documentation of proceedings of the GCAC;

(j) register participants as contemplated in code 14; and

(k) function as a formal communication channel for the GCAC.

(3) The secretariat must make the latest version of the grid code available electronically and notify all participants of approved amendments or exemptions within one week of receipt of approval by the Minister of Mines and Energy.

(4) The secretariat must make hard copies of the latest version of the grid code available to requesting entities, for which a nominal fee may be charged to recover reproduction costs.

PART 2REGISTRATION OF PARTICIPANTS AND GRID CODE

AMENDMENT OR EXEMPTION

Registration and deregistration of participants

9. (1) A participant may be registered by the secretariat as a generator, distributor, end-use customer, service provider, retailer or market participant.

(2) A participant must apply in writing to the secretariat to be registered as contemplated in subcode (1).

(3) A participant may not have access to the transmission system unless the participant is registered as contemplated in subcode (1).

(4) Service providers must ensure that customers are registered as participants before entering into a contract for licenced services with the customers.

(5) A participant who intends to deregister must notify the secretariat at least six months before the intended date of deregistration and the deregistration must be carried out in accordance with guidelines determined by the Board.

Transmission Grid Code amendment or exemption process

10. (1) A participant, a member of the GCAC or a member of the Board -


(a) may in writing to the Minister propose amendments to the Transmission Grid Code; and

(b) who proposes amendments pursuant to paragraph (a), must submit the proposed amendments to the secretariat as contemplated in code 11(4).

(2) A participant -

(a) may in writing to the Minister apply for an exemption from complying with provisions of the Transmission Grid Code; and

(b) who applies for an exemption pursuant to paragraph (a), must submit the application to the secretariat as contemplated in code 11(4).

(3) On receipt of the proposed amendments contemplated in subcode (1) or the application contemplated in subcode (2) -

(a) the secretariat must submit the proposed amendments or the application to the GCAC for review; and

(b) subject to paragraph (a) and code 7, the GCAC must review the proposed amendments and subject to code 12(1), make recommendations to the Board.

(4) Subject to code 12, the Minister -

(a) may approve the amendments proposed under subcode 1; or

(b) must approve and grant an exemption applied for under subcode 2, if the exemption is necessary to -

(i) provide for existing equipment that has not been designed with consideration for the provisions of the Transmission Grid Code;

(ii) facilitate transition through interim arrangements; or

(iii) facilitate temporary conditions necessitating exemption.

(5) The GCAC must keep a register which contains a list of exemptions that have been approved under subcode (4), with the relevant expiry date and the reference number.

(6) The procedure for the amendment of, or exemption from, the Transmission Grid Code as contemplated in subcodes (1) to (4) inclusive, is sketched in Annexure 1.

Submissions to GCAC

11. (1) The secretariat must make available a list of submission dates aligned with GCAC annual meetings for each year by November of the preceding year.

(2) Urgent submissions must be dealt with at ad hoc meetings of the GCAC as decided by the Chairperson upon advice from the secretariat.

(3) The secretariat must issue guidelines for submissions to the GCAC and the guidelines must be published together with the submission dates on the website of the Board.


(4) An application for an amendment or exemption must be submitted, in accordance with the guidelines, to the secretariat and the applicant must state the relevant clauses of the Transmission Grid Code and give reasons for the application.

(5) The GCAC must initiate the review process without delay and must -

(a) if necessary, ensure that the submission is referred to an expert team for detailed assessment,clarificationandreformulationorrecommendation;and

(b) forward the recommendation to the Board for consideration once it has been finalized.

(6) The GCAC must take the complexity and importance of the amendment or exemption into account in deciding on the composition of the expert team that will deal with the submission.

(7) The secretariat must inform the applicant of the expected time frames for dealing with the submission.

(8) The applicant must be allowed to make representation to the expert team or the GCACpriortotheformulationorfinalizationoftheGCACrecommendationtotheBoard.

Recommendation to Board

12. (1) Once the GCAC has reviewed submissions, the secretariat must prepare the formal recommendation to the Board on all proposed amendments to, and exemptions from, the Transmission Grid Code.

(2) In the recommendation contemplated in subcode (1), the secretariat must include -

(a) a clear expression of divergent views on the proposed amendments and exemptions if any were received by the secretariat; and

(b) an appropriate implementation date for the proposed amendments and exemptions.

(3) Despite any code to the contrary, the Minister may grant full or partial exemption to participants from complying with any code.

(4) The Board must submit its recommendations for amendments or exemptions to the Minister for approval.

(5) Amendments and exemptions must have an implementation date stipulated by the Minister.

(6) The Board must give notice to the secretariat of the decisions reached by the Board and the Minister.

(7) The secretariat is responsible for communicating the decisions contemplated in subcode (6) to participants.

(8) The secretariat must update the Transmission Grid Code with the approved amendments and exemptions.


PART 3DISPUTE MEDIATION, RESOLUTION AND APPEAL MECHANISM

Dispute mediation, resolution and appeal mechanism

13. (1) A registered participant must have a documented procedure for handling disputes arising under the Transmission Grid Code.

(2) The procedure contemplated in subcode (1) must cover the aspects contemplated in code 17.

Complaints about operations of GCAC

14. (1) Any complaint regarding the operations of the GCAC must be addressed in writing to the secretariat.

(2) The GCAC must attend to the complaints contemplated in subcode (1) at or before the next session.

(3) If a complaint contemplated in subcode (1) is not resolved at the meeting contemplated in subcode (2), the matter must be referred to the Board in accordance with code 17.

Disputes about decisions of Board

15. (1) Any objection to decisions by the Board must be made in writing to the Board.

(2) Participants who are aggrieved by decisions taken by the Board may appeal to the Minister, against the decisions taken by the Board, in accordance with Section 34 of the Act.

Disputes about decisions of Minister

16. (1) Any objection to decisions by the Minister must be made in writing to the Minister.

(2) Participants who are aggrieved by decisions taken by the Minister may appeal to the High Court against the decisions taken by the Minister.

Complaints among customers and service providers

17. (1) The procedure for handling complaints must include the incident report and non-conformance report requirements set out in codes 18 and 19.

(2) The Board must develop a database of disputes resolved to assist in the resolution of future disputes.

(3) If the outcome of a dispute resolution proceeding requires or implies an amendment totheTransmissionGridCode,theBoardmustfirstconsultwiththeGCAC.

Incident report

18. (1) An incident report should be seen as a formal communication of a problem.

(2) A customer may issue an incident report to a service provider on becoming aware of a problem or a possible breach of the Transmission Grid Code.


(3) The service provider contemplated in subcode (2) must provide a reasonable explanation and if appropriate indicate what action it will take to address the problem.

(4) A service provider may issue an incident report to a customer if the customer is suspected of not complying with the necessary Transmission Grid Code requirements and the customer must provide the service provider with a reasonable explanation and where appropriate indicate the measures that the customer will take to address the problem.

(5) A service provider must keep a log of all incident reports received and a log of all incident reports communicated to customers.

(6) Incident reports are operational in nature and generally require action only by technical and customer relations staff.

Non-conformance report

19. (1) A customer may issue a non-conformance report when it is suspected that -

(a) the service provider has -

(i) failed to provide a reasonable explanation;

(ii) wilfully misrepresented the facts concerning an incident; or

(iii) failed to implement the agreed preventative actions within the agreed time frame;

(b) the number of incident reports is excessive in relation to historical performance; or

(c) the actions or undertakings arising from a mediation or arbitration process have not been performed or adhered to.

(2) A service provider may issue a non-conformance report when it is suspected that -

(a) the customer has failed to provide a reasonable explanation;

(b) the customer has wilfully misrepresented the facts concerning an incident; and

(c) the customer has failed to implement the agreed preventative actions within the agreed time frame;

(d) the number of incident reports is excessive in relation to historical performance; or

(e) the actions or undertakings arising from a mediation or arbitration process have not been performed or adhered to.

(3) Non-conformance reports are indications of problems that require managerial intervention by the service provider or customer.

(4) In the case where the parties agree with the non-conformance report, recommended action must be agreed upon and both participants must implement the recommended action within an agreed time frame.

(5) Service providers must report annually to the Board on the following aspects of the procedure:


(a) Number of non-conformance reports for each customer category;

(b) Number of closed out non-conformance reports for each customer category; and

(c) Number of disputes resolved.

(6) A dispute may be declared when the parties cannot agree on the non-conformance report or the recommendations of the non-conformance report or when the agreed recommendations are not implemented in the agreed time frame.

Submission of disputes to Board

20. (1) A party may submit a dispute to the Board in accordance with the procedures contemplated in codes 14 and 17.

(2) When a dispute is submitted to the Board as contemplated in subcode (1) or referred to the Board as contemplated in code 14(3) the parties must provide the following information:

(a) full history of relevant incident reports;

(b) detailed non-conformance report and accompanying information that gave rise to the dispute; and

(c) written report from each participants detailing the reason for not being able to close out the non-conformance report.

(3) When a dispute that has not followed the relevant procedure reaches the Board, the Board must refer the party to the correct process.

(4) The Board must conduct a dispute mediation process and act as the mediator to the dispute in accordance with -

(a) section 3(2)(c) of the Act; and

(b) the dispute mediation procedural rules of the Board.

(5) If the dispute mediation process contemplated in subcode (4) succeeds, the parties must strive to honour their respective undertakings or actions agreed upon to the best of their abilities.

(6) If the dispute mediation process contemplated in subcode (4) fails to provide the partieswithanagreedsolution,thepartiesmustreferthemattertoarbitrationforfinaldecision.

(7) If the issue to be resolved at the mediation contemplated in subcode (4) is primarily -

(a) an accounting matter, there must be one arbitrator who is an independent Chartered Accountant;

(b) a legal matter, there must be one arbitrator who is a senior counsel; or

(c) a technical matter, there must be one arbitrator who is a person with suitable technical knowledge.

(8) The appointment of the arbitrator must be agreed between the parties, but failing agreement between them within a period of 14 days after the arbitration has been demanded, either of the parties may request the Board to make the appointment and, in making the appointment, to have regard to the nature of the dispute.


(9) Each arbitration must be in Windhoek in accordance with the provisions of Namibian arbitration laws.

(10) The following must be considered, amongst other things, during the arbitration process:

(a) existing and historical performance trends or practices;

(b) reference standards;

(c) appropriate network design or operation standards;

(d) precedents with similar events;

(e) historical agreements between the participants; and

(f) total cost impact.

(11) Therulingofthearbitermustincludeatimeframeforimplementationandisfinaland binding on the parties.

PART 4COMPLIANCE, CODE AUDITS, CONTRACTING AND VERSION CONTROL

Compliance

21. (1) All participants must comply with the Transmission Grid Code.

(2) Participants must inform the Board of any non-conformance report of a material nature that has been submitted to another participant as contemplated in code 24.

(3) The Board may require a participant to provide the Board with information that the Board considers necessary for the proper administration of the Transmission Grid Code and that informationmustonrequestbetreatedasconfidential.

(4) Upon a report or suspicion of non-compliance the Board may seek to -

(a) resolve the issue through negotiation;

(b) take action in terms of the procedures for handling licensing contraventions;

(c) consider an application for amendment; or

(d) consider an application for exemption.

(5) Customers may apply for exemption from changes to the Transmission Grid Code as contemplated in code 10.

Code audits

22. (1) A customer may request from the service provider or a service provider may request from a customer, any material in the possession or control of that participant relating to compliance with a particular code of the Transmission Grid Code.


(2) If a participant makes a request in relation to a particular code of the Transmission Grid Code as contemplated in subcode (1) the participant may not request information relating to that same code of the Transmission Grid Code within six months.

(3) A request contemplated in subcode (1) must include the following information:

(a) nature of the request;

(b) name of the representative appointed by the requesting participant to conduct the investigation; and

(c) the time or times at which the information is required.

(4) The participant contemplated in subcode (1) -

(a) may not unreasonably withhold any relevant information requested; and

(b) must provide a representative of the requesting participant with access to all relevant documentation, data and records, including computer records or systems, as is reasonably requested.

(5) The information contemplated in subcode (4)must be treated as confidential onrequest to do so.

(6) A request contemplated in subcode (1) or an investigation must be conducted without undue disruption to the business of the participant.

Contracting

23. (1) The Transmission Grid Code must comprise one of the standard documents that form part of the contract between participants.

(2) Service providersmust contractwith customers for any services specified in theTransmission Grid Code in accordance with the contracting framework sketched in Annexure 2.

(3) Service providers must ensure that a non-discriminatory procedure is developed and implemented for the allocation of quality of supply parameters at the points of common coupling.

(4) Customers must enter into a connection contract and an operating agreement with the transmission company in advance of construction of the connection facilities.

(5) Customers must enter into a use-of-system contract with the transmission company before commencement of energy transactions over the transmission system.

(6) Customers must enter into an ancillary services contract with the transmission company before commencement of ancillary services delivery to the transmission company.

Version control

24. (1) The Transmission Grid Code will evolve as the electricity supply industry in Namibia evolves.

(2) The chapters and codes that collectively form the grid code must have separate version control and approvals.


(3) The secretariat is responsible for version control.

CHAPTER 3TRANSMISSION SYSTEM NETWORK

PART 1TRANSMISSION SYSTEM CONNECTION PROCESS AND CONDITIONS

Applications for transmission system connections

25. (1) The transmission company must provide quotes for new connections or for upgrading existing connections, according to a tariff methodology approved by the Board, within time frames agreed with prospective customers.

(2) The agreed time period for connecting customers or upgrading connections must be negotiated between the transmission company and the customer in every instance.

(3) Applications for new or revised connections must be lodged with the transmission company at NamPower Centre, 15 Luther Street, Windhoek. Objective of connection conditions

26. (1) The -

(a) customer connected to or seeking connection to the transmission system or embedded generator or co-generator, must comply with the acceptable technical, design and operational criteria; and

(b) transmission company and system operator must comply with the minimum technical, design and operational criteria in relation to the part of the transmission system where the connection will take place.

(2) Theobjectiveoftheconnectionconditionsspecifiedincodes27to72istoensure-

(a) that by specifying minimum technical, design and operational criteria, the basic rules for connection to the transmission system -

(i) are similar for all customers of an equivalent category; and

(ii) will enable the Transmission company and system operator to comply with its statutory and licence obligations;

(b) adherence to sound engineering practice and codes by all the participants since quality of supply and grid integrity are shared responsibilities between the Transmission company and system operator and their customers.

Generator connection conditions

27. (1) The Transmission Grid Code requirements for generator connections are set out in subcodes (2), (3) and (4).

(2) The Transmission Grid Code requirements must be read with the generating unit characteristicsandsizesspecifiedinTable1and2inAnnexure3.


(3) The transmission company must offer to connect generators and upon signing of an agreement to connect a generator entered into by the transmission company and a generator licenced to generate electricity who has applied under code 25(3), the transmission company must make available a point of connection to that generator.

(4) For new generating units special consideration must be given to the impact of the risks on future operating costs and the system operator is to quantify the expected future operating costs.

(5) The special consideration contemplated in subcode (4) may include obtaining approval of the Board for including the expected future operating costs in the tariff base or obliging the generator to purchase reserves.

Protection

28. (1) The unit step-up transformer, unit auxiliary transformer, associated busbar ducts and switchgear of a generating unit must be equipped with well maintained protection functions, in line with international best practices, to rapidly disconnect appropriate plant sections should a fault occur within the relevant protection zones of the transmission system.

(2) The protection functions contemplated in code 29, 30, 31, 32, 33, 34, 35 or 36 may beusedasspecifiedinthatcodetoprotecttheinterconnectedpowersystem.

Backup impedance

29. (1) An impedance facility with a large reach must be used.

(2) The impedance facility contemplated in subcode (1) must operate for phase faults in the unit, in the high voltage yard or in the adjacent transmission system lines, with a suitable delay, for cases when the corresponding main protection fails to operate.

(3) The impedance facility contemplated in subcode (1) must have fuse fail interlocking.

Loss of field

30. (1) Ageneratingunitmustbefittedwithalossoffieldfacilitythatmatchesthesystem requirements.

(2) Thetypeoflossoffieldfacilitycontemplatedinsubcode(1)mustbeagreedwiththetransmission company.

Pole slipping facility

31. Ageneratingunitmustbefittedwithapoleslippingfacilitythatmatchesthesystemrequirements, where the system operator determines that it is required.

Trip to house load

32. (1) A trip to house load protection must operate as follows in the event of a complete loss of load -

(a) ifallthefeederbreakersopenatapowerstation,powerflowintothesystemiscutoff and the generators will accelerate;

(b) at 50.5 Hz the over-frequency facility must pick up to start the house loading process and the high voltage breakers will still be closed;


(c) there will be power swings between the units and as soon as a generating unit has a reverse power condition the trip to house load protection must open the high voltage breaker; and

(d) the units must island feeding their own auxiliaries.

(2) When system conditions have been restored then the islanded units can be resynchronised to the transmission system.

Unit transformer high voltage back-up earth fault protection

33. (1) Unit transformer high voltage back-up earth fault protection is an inverse definiteminimumtimefacilitythatmustmonitorthecurrentintheunittransformerneutral.

(2) The unit transformer high voltage back-up earth fault protection can detect faults in the transformer high voltage side or in the adjacent network.

(3) The unit transformer high voltage back-up earth fault protection facility contemplated in subcode (1) must trip the high voltage circuit breaker.

High voltage breaker fail protection

34. (1) The high voltage breaker fail protection must monitor the operation of the high voltage circuit of the circuit breaker for protection trip signals.

(2) Ifacircuitbreaker fails toopenand the fault isstillpresentafteraspecific timedelay, nominally 120 ms, it must trip the necessary adjacent circuit breakers.

High voltage pole disagreement protection

35. The high voltage pole disagreement protection must cover the cases where one or two poles of a circuit breaker fail to operate after a trip or close signal.

Unit switch onto standstill protection

36. (1) A unit switch onto standstill protection must be installed in the high voltage yard substation or in the unit protection panels.

(2) If the protection contemplated in subcode (1) is installed in the unit protection panels then the direct current supply for the unit switch onto standstill protection and the protection used for the circuit breaker closing circuit must be the same to safeguard the generator against an unintended connection to the transmission system, back energisation, when at standstill or at low speed.

(3) In addition, should system conditions dictate, other protection requirements must be determined by the system operator in consultation with the generator and these should be provided and maintained by the relevant generator at its own cost.

(4) Required high voltage breaker tripping, fault clearance times, including breaker operatingtimesdependonsystemconditionsandmustbedefinedbythetransmissioncompany.

(5) The guidelines for the operating times contemplated in subcode (4) are -

(a) 80 ms where the point of connection is 330kV or above;

(b) 80 ms where the point of connection is 220 kV; or


(c) 100 ms where the point of connection is 132 kV and below.

(6) Further downstream breaker tripping-away from the system, fault clearing times, including breaker operating time, must not exceed -

(a) 120 ms plus additional 30 ms for DC offset decay; or

(b) 100 ms plus additional 40 ms for DC offset decay.

(7) Where system conditions dictate, the times contemplated in subcodes (5) and (6) may be reduced.

(8) Where so designed, earth fault clearing times for high resistance earthed systems may exceed the tripping times contemplated in subcodes (5) and (6).

(9) All protection interfaces with the transmission company must be co-ordinated between the participants.

(10) The settings of all the protection tripping functions on the unit protection system of a unit, relevant to the interconnected power system performance and as agreed with each generator in writing, must be co-ordinated with the transmission protection settings.

(11) The transmission protection settings contemplated in subcode (10) must be agreed between the transmission company and the generator and must be documented and maintained by thegeneratorwiththereferencecopywhichreflectstheactualplantstatusheldbythetransmissioncompany and the generator must control all other copies of the documented protection settings.

(12) For system abnormal conditions, a unit is to be disconnected from the transmission system in response to conditions at the point of connection, only when the system conditions are outside the plant capability where damage will occur.

(13) Protection setting documents must illustrate plant capabilities and the relevant protection operations.

(14) Competent persons must carry out testing, commissioning and configuration ofprotection systems.

(15) Prototype and routine testing of protection systems must be carried out as set out under item 5(1) in Annexure 4.

(16) Any work, including work done during a unit outage, on the protection circuits interfacing with transmission protection systems must be communicated to the system operator before commencing with the works.

Ability of units to island

37. (1) Every unit that does not have black start capabilities of less than one hour without power from the transmission system must be capable of unit islanding.

(2) Islanding testing must be contracted as an ancillary service.

(3) The procedure for islanding testing contemplated in subcode (2) is set out under item 5(2) in Annexure 4.

Excitation system requirements


38. (1) A continuously-acting automatic excitation control system (AVR) must be installed to provide constant terminal voltage control of the unit, without instability, over the entire operating range of the unit.

(2) A continuously-acting automatic excitation control system does not include the possibleinfluenceofapowersystemstabiliser.

(3) ExcitationsystemsmustcomplywiththerequirementsspecifiedinIEC60034.

(4) The excitation control system must be equipped with an under-excitation limiter, loadanglelimiterandfluxlimiterasdescribedinIEC60034-16-1.

(5) The excitation system must have a minimum excitation ceiling limit of 1.6 pu rotor current, where 1 pu is the rotor current required to operate the unit at rated load and at rated power factor.

(6) The settings of the excitation system contemplated in subcode (1) must be agreed between the system operator and each generator.

(7) The settings agreed between the system operator and a generator as contemplated in subcode (6) must be documented.

(8) The master copy of the settings documented as contemplated in subcode (7) must be held by the system operator.

(9) The generators must control all other copies following the procedure set out in item 5(3) in Annexure 4.

(10) In addition, the unit must be capable of operating in the full range set out in the capability chart referred to in item 2 in Annexure 9.

(11) The capability of a unit to operate in full range as contemplated in subcode (9) must be tested using the test procedures shown in item 5(5) in Annexure 4.

(12) The active power output under steady state conditions of any unit must not be affected by voltage changes in the normal operating range.

(13) Units with water-cooled stator windings must be capable of delivering rated Megavolt-Ampere (MVA) at terminal voltages between 95% and 105% of rated voltage.

(14) Unitswithgas-cooledstatorwindingsarespecifiedtobecapableofdeliveringratedMVA at terminal voltages between 100% and 105% of rated voltage and rated stator current at voltages below 100%.

(15) Power system stabilisers as described in IEC60034-16-1 are a requirement for all newunits,andforexistingunitsretrofittingmayberequireddependingontheinterconnectedpowersystem requirements.

(16) The requirements for other excitation control facilities and continuously-acting automatic excitation control system (AVR) refurbishment must be determined in conjunction with the system operator.

(17) Routine and prototype response tests must be carried out on excitation systems as indicated in item 5(3) in Annexure 4 and in accordance to IEC60034-16-3.

Reactive capabilities


39. (1) All new units must be capable of supplying rated power output Megawatt (MW) at any point between the limits 0.85 power factor lagging and 0.95 power factor leading at the unit terminals.

(2) Reactiveoutputmustbefullyvariablebetweenthelimitsspecifiedinsubcode(1)under continuously-acting automatic excitation control system (AVR), manual or other control.

(3) Routine and prototype response tests must be carried out to demonstrate reactive capabilities as indicated in item 5(5) in Annexure 4.

Multiple unit tripping (MUT) risks

40. A power station and its units must be designed, maintained and operated to minimise the risk of more than one unit being tripped from one common cause within a short time.

Governing design requirements

41. All units above 2.5 MVA must have an operational governor that must be capable of responding according to the minimum requirements set out in codes 43 to 53.

Governing system frequency variations

42. (1) Because of the uncertain dynamic behaviour of the Namibian system, frequencyvariationscannotbespecifiedintheTransmissionGridCode.

(2) New Generators will need to do comprehensive system studies to ascertain the dynamic behaviour of the system as applicable to their position on the network.

(3) Thefrequencytolerancesapplytovoltagetolerancesasspecifiedincode57.

High frequency requirements for turbo-alternators

43. (1) All synchronised units must respond by reducing active power to frequencies above 50 Hz plus allowable dead band described in code 53.

(2) Speed governors must be set to give a four percent governor droop characteristic or as otherwise agreed by the system operator.

(3) The response under subcodes (1) and (2) must be fully achieved within 10 seconds and must be sustained for the duration of the frequency excursion.

(4) The unit must respond to the full designed minimum operational capability of the unit at the time of the occurrence.

Over-frequency conditions in range of 51.5 to 52 Hz (stage H1)

44. (1) When the frequency goes above the range of 51.5 Hz but less than 52 Hz the requirement is that the unit must be designed to run for at least 10 minutes over the life of the plant.

(2) Theturbo-alternatorunitsmustbeabletooperateforatleastfiveminutescontinuouslywithout tripping in the range contemplated in subcode (1).

(3) Exceeding the limit of 53Hz must prompt the generator to take all reasonable efforts


to reduce the system frequency below 51.5Hz, including manual tripping of the running unit.

(4) Tripping must be staggered in time and be initiated once the frequency has been greaterthan51.5Hzforfiveminutes.

(5) The generator will trip a unit, and if the system frequency does not fall below 51.5 Hz,theotherunitsmustbetrippedinstaggeredformatoverthenextfiveminutesoruntilthesystemfrequency is below 51.5 Hz.

(6) The system operator must approve the tripping requirements and procedures contemplated in subcodes (1) to (5).

Over-frequency conditions above 52 Hz (stage H2)

45. (1) When the frequency goes above 52 Hz the requirement is that the unit must be designed to run for at least 1 minute over the life of the plant.

(2) The turbo-alternator units must be able to operate at least 30 seconds continuously without tripping in this range.

(3) When the system frequency exceeds 52 Hz, the generator can start tripping units sequentially and the tripping must be spread over a 30 second window.

(4) If a generator chooses to implement automatic tripping, the tripping must be staggered.

(5) The system operator must approve this the tripping requirements and procedures. As

anexample,thefirstunitwilltripin5seconds,thesecondunittripin10seconds,etc.

High frequency requirements for hydro alternators

46. (1) All synchronised hydro units must respond by reducing active power to frequencies above 50 Hz plus allowable dead band described in code 53.

(2) Speed governors must be set to give a four percent governor droop characteristic or as otherwise agreed by the system operator.

(3) The response under subcodes (1) and (2) must be fully achieved within 10 seconds and must be sustained for the duration of the frequency excursion.

(4) The unit must respond to the full load capability range of the unit.

(5) As the Namibian system is not designed for n-1 contingencies high over-frequency withstand capabilities are required.

(6) When the frequency goes above 54 Hz the unit must be designed to run for at least 120 seconds over the life of the plant.

(7) It is expected that there will be less than 30 events of high frequencies of over 54 Hz for the lifetime of the unit of 50 years therefore the hydro-alternator units must be able to operate at least 4 seconds in the range of frequencies above 54 Hz.

(8) When the system frequency increases to 54 Hz for longer than four seconds, the


generator must start staggered tripping of units as per the procedure for turbo-alternators.

(9) Settings of the staggered tripping of the units must be agreed with the system operator.

Low frequency requirements for turbo-alternator units

47. (1) All turbo-alternator units must be designed to be capable of having a four percent governor droop characteristic or as otherwise agreed by the system operator with a minimum response of three percent of maximum continues rating within 10 seconds of a frequency incident.

(2) The minimum response contemplated in subcode (1) must be sustained for at least 10 minutes.

Low frequency in range of 48.5 to 48.0 Hz (StageL1)

48. (1) When the frequency is in the range of below 48.5 Hz but greater than 48.0 Hz, the turbo-alternator unit must be designed to run for at least 10 minutes over the life of the plant.

(2) Theunitmustbeabletooperateatleastfiveminutescontinuouslywithouttrippingwhile the frequency is in the range referred to in subcode (1).

(3) Ifthesystemfrequencyisintherangereferredtoinsubcode(1)formorethanfiveminutes, independent action may be taken by a generator to protect the unit.

Low frequency in range of 48.0 to 47.5 Hz (Stage L2)

49. (1) When the frequency goes below 48.0 Hz but greater than 47.5 Hz a turbo-alternator unit must be designed to run for at least one minute over the life of the plant.

(2) A turbo-alternator unit must be able to operate at least 30 seconds continuously without tripping while the frequency is in the range of below 48.0 Hz but greater than 47.5 Hz.

(3) If the system frequency is in the range contemplated in subcode (2) for more than 30 seconds, independent action may be taken by a generator to protect the turbo-alternator unit.

Low frequency below 47.5 Hz (Stage L3)

50. If the system frequency falls below 47.5 Hz for longer than six seconds, independent action may be taken by a generator to protect the unit.

Low frequency requirements for hydro-alternator units

51. (1) All reasonable efforts must be made by the generator to avoid tripping of the hydro-alternator for under frequency conditions provided that the system frequency is above 46 Hz.

(2) If the system frequency falls below 46 Hz for more than one second, independent action may be taken by a generator to protect the hydro-alternator unit and the action may include automatic tripping.

Droop

52. The speed governor must be capable of being set so that it operates with an overall speed droop of between two percent and nine percent.


Dead band

53. (1) The maximum allowable dead band must be 0.15 Hz for governing.

(2) The allowable dead band for governing contemplated in subcode (1) means that no response is required from the unit while the frequency is greater than 49.85 to and less than 50.15 Hz.

(3) Routine and prototype response tests must be carried out on the governing systems as indicated in item 5(4) in Annexure 4.

Thermal power stations restart after power station black-out

54. (1) A power station and a unit is to be capable of being restarted and synchronised to the interconnected power system following restoration of external auxiliary AC supply without unreasonable delay resulting directly from the loss of external auxiliary AC supply.

(2) For the purposes of Chapter 3, examples of unreasonable delay in the restart of a power station are -

(a) restartofthefirstunitthattakeslongerthanfourhoursafterrestartinitiation;

(b) restart of the second unit that takes longer than two hours after the synchronising of thefirstunit;

(c) restarting of all other units that take longer than one hour each after the synchronising of the second unit;

(d) delays not inherent in the design of the relevant start up facilities and which could reasonably be minimised by the relevant generator; or

(e) the start up facilities for a new unit not being designed to minimise start up time delays for the unit following loss of external auxiliary AC supplies for two hours or less.

(3) Routine and prototype response tests must be carried out to demonstrate capabilities as indicated in item 5(7) in Annexure 4.

Hydro and gas turbines restart after power station black-out

55. (1) A power station and a unit is to be capable of being restarted and synchronised to the interconnected power system following restoration of external auxiliary AC supply without unreasonable delay resulting directly from the loss of external auxiliary AC supply.

(2) For the purposes of Chapter 3, examples of unreasonable delay in the restart of a power station are -

(a) restartofthefirstunitthattakeslongerthan30minutesafterrestartinitiation;

(b) restarting of all other units that take longer than 30 minutes each after the synchronisingofthefirstunit;

(c) delays not inherent in the design of the relevant start up facilities and which could reasonably be minimised by the relevant generator; and


(d) the start up facilities for a new unit not being designed to minimise start up time

delays for the unit following loss of external auxiliary AC supplies for 30 minutes or less.


Black starting

56. (1) Power stations that have declared that they have a station black start capability must demonstrate this facility by test as described in item 5(7) in Annexure 4.

(2) Back start capable power stations may be called from time to time not to carry out a

full station black start but a unit black start as described in item 5(8) in Annexure 4.

External supply disturbance withstand capability

57. (1) Any unit and any power station equipment must be designed with anticipation of the following voltage conditions at the point of connection:

(a) a voltage deviation in the range of 90% to 110% for protracted periods;

(b) a voltage drop to zero for up to 0.2s, to 75% for 2s, or to 85% for 60 s provided that during the three minute period immediately following the end of that 0.2s, 2s, or 60s periods the actual voltage remains in the range 90-110% of the nominal voltage;

(c) unbalance between phase voltages of not more than three percent negative phase sequenceandorthemagnitudeofonephasenotlowerthanfivepercentthananyofthe other two for six hours; and

(d) a requirement to withstand the automatic reclosing cycle for faults on the transmission lines connected to the power station, being three single phase faults, each of 150 ms duration, within 31 seconds.

(2) ThevoltagetolerancesapplytofrequencytolerancesasspecifiedinAnnexure5.


On load tap changing for generating unit step-up transformers

58. (1) All generating unit step-up transformers must have on-load tap changing which can be remotely controlled.

(2) The range for the on-load tap change contemplated in subcode (1) must be agreed between the transmission company and the generator.

Emergency unit capabilities

59. All generators must specify the capabilities of their units for providing emergency levels 1 and 2 support under abnormal power system conditions as contemplated in code 178.

Facility for independent generator action


60. (1) Frequency control under system island conditions must revert to the power stations as the last resort, and units and associated plant must be equipped to handle such situations.

(2) The required control range is from 49 Hz to 51 Hz.

Automatic under-frequency starting

61. (1) It may be agreed with the system operator that a unit that is capable of automatically starting within 10 minutes must have automatic under-frequency starting.

(2) This starting must be initiated by frequency-level facilities with settings in the range 49Hzto50Hzasspecifiedbythesystemoperator.

Testing and compliance monitoring

62. (1) A generator must keep records relating to the compliance by each of its units setting out the information that the system operator reasonably requires for assessing power system performance including actual unit performance during abnormal conditions.

(2) Within one month after the end of June and December, a generator must review, and confirmtothesystemoperator,compliancebyeachoftheunitsofthatgeneratorwithitems5(1)to(11) in Annexure 4 during the past six month period.

(3) A generator must conduct tests or studies to demonstrate that each power station and each generating unit complies with each of the requirements of this Chapter.

(4) If a new unit is installed after an outage occurs as a result of a compromise on any of the procedures contemplated in item 5(1) to (11) in Annexure 4, the generator must carry out tests on the new unit to demonstrate that the unit complies with the relevant procedure.

(5) The generator must continuously monitor its compliance with all the connection conditions of the Transmission Grid Code.

(6) A generator must submit to the system operator a detailed test procedure, emphasising system impact, for the relevant part of this Chapter prior to every test.

(7) If a generator determines, from tests or otherwise, that one of its units or power stations is not complying with one or more codes in this Chapter, then the generator must -

(a) promptly notify the system operator of that fact;

(b) promptly advise the system operator of the remedial steps it proposes to take to ensure that the relevant unit or power station can comply with this Chapter and the proposed timetable for implementing those steps;

(c) diligently take remedial action that will ensure that the relevant unit or power station can comply with this Chapter;

(d) regularly report in writing to the system operator on its progress in implementing the remedial action; and

(e) after taking remedial action as contemplated in paragraph (a), demonstrate to the reasonable satisfaction of the system operator that the relevant unit or power station is then complying with this Chapter.

Non-compliance suspected by the system operator


63. (1) If at any time a system operator believes that a unit or power station is not complying with a code in this Chapter, the system operator must -

(a) notify the relevant generator of the non-compliance; and

(b) specify the code concerned and the basis for the belief.

(2) If the generator contemplated in paragraph (a) subcode (1) believes that the unit or power station is complying with the code contemplated in paragraph (b) of that subcode, the system operator and the generator must promptly meet to resolve their difference.

Unit modifications

64. (1) If a generator proposes to change or modify any of its units in a manner that -

(a) could reasonably be expected to adversely affect the ability of that unit to comply with this Chapter; or

(b) changes the performance, information supplied or settings,

the generator must submit a proposal notice to the system operator which -

(i) containsdetailedplansoftheproposedchangeormodification;

(ii) states when the generator intends to make the proposed change or modification;and

(iii) setsouttheproposedteststoconfirmthattherelevantunitaschangedormodified operates in the manner contemplated in the proposal and cancomply with this Chapter.

(2) If the system operator disagrees with the proposal submitted as contemplated subcode (1), the system operator may notify the relevant generator, and the system operator and the relevant generator must promptly meet and discuss the matter in good faith in an endeavour to resolve the disagreement.

(3) Thegeneratormustensurethatanapprovedchangeormodificationtoaunitortoasubsystem of a unit is implemented in accordance with the relevant proposal approved by the system operator.

(4) The generator must notify the system operator promptly after an approved change or modificationtoaunithasbeenimplemented.

(5) The generatormust confirm that a change ormodification to any of its units asconforms to the relevant proposal by conducting the relevant tests, in relation to the connection conditions, promptly after the proposal has been implemented.

(6) Within 20 business days after any the tests contemplated in subcode (5) has been conducted, the relevant generator must provide the system operator with a report in relation to that test including test results of that test, where appropriate.

Equipment requirements


65. (1) Where the generator needs to install equipment that connects directly with transmission company equipment, the equipment must adhere to the transmission company design requirements as set out in Part 2 of this Chapter.

(2) The transmission company may require customers to provide documentary proof that their connection equipment complies with all relevant standards, both by design and by testing.

Connection conditions for distributors and end-use customers

66. (1) The transmission company must offer to connect and, subsequent to the signing of the relevant agreements, make available a point of connection to any requesting distributor or end-use customer.

(2) A customer may request additional reinforcements to the transmission system over andabovethatwhichcouldbeeconomicallyjustifiedascontemplatedinPart3ofthisChapter.

(3) The transmission company must provide such reinforcements if the customer agrees to bear the costs, which must be priced according to the tariffs approved by the Board.

Power factor

67. (1) Distributors and end-use customers must take all reasonable steps to ensure that the power factors at the point of supply is at all times 0,85 lagging or better, unless otherwise agreed to in existing contracts between the participants.

(2) This requirement applies to each point of supply individually for customers with more than one point of supply.

(3) A leading power factor must not be acceptable, unless specifically agreed to inwriting.

(4) Should the power factor be less than the said limit during any 10 demand-integrated half hours in a single calendar month, the participants must co-operate in determining the plans of action to rectify the situation.

(5) Overall lowest cost solutions must be sought.

Protection

68. (1) Each participant must take all reasonable steps to protect its own plant.

(2) The system operator protection requirements, with which the customers must interface, are described in code 86.

(3) The detailed protection applications, insofar as the equipment of one participant may have an impact on the other, must be agreed to in writing by the relevant participants.

(4) Distributors who have customers connected directly to the transmission substations are responsible for ensuring that the customers comply with the relevant protection standards.

(5) The participants must co-ordinate protection to ensure proper grading and protection coordination.

Fault levels

69. (1) Minimum fault levels at each point of supply must be maintained by the


transmission company under normal operating conditions to ensure compliance with the relevant quality of supply standards and to ensure correct operation of the protection systems.

(2) The transmission company must liaise with customers in accordance with the process set out in codes 133 to 162 on how fault levels are planned to change and best overall solutions when equipment ratings become inadequate.

(3) Overall lowest cost solutions must be sought and a joint impact assessment must be done covering all aspects.

(4) The transmission company must communicate the potential impact on safety of people when equipment ratings are exceeded.

(5) The system operator must bi-annually or when substantial deviations have taken place, publish updated minimum and maximum normal operating fault levels for each point of supply.

(6) Thecustomermust ensurehis equipment is capableofoperatingat the specifiedfault level ranges.

(7) If equipment fault level ratings are or will be exceeded, the customer must promptly notify the transmission company.

(8) The transmission company must seek overall lowest cost solutions to address fault level problems.

(9) Corrective action must be at the cost of the relevant asset owner.

Distributor or end-use customer network performance

70. (1) If the distributor or end-use customer network performance falls below acceptable levels and affects the quality of supply to other customers or causes direct or indirect damage to the transmission company equipment, the process for dispute resolution set out in code 18 read with code 15 must be followed.

(2) Acceptable network performance must be -

(a) performance comparable to benchmarks for similar networks;

(b) performance that complies with the transmission company operating and maintenance procedures at that substation; and

(c) performance that complies with the minimum agreed standards of quality of supply, as contemplated in code 71.

(3) If a distributor or end-use customer is aware that the network performance of the distributor or end-use customer may not comply with subcode (2), the distributor or end-use customer as the case may be must take reasonable steps, at own cost, to overcome the shortcomings by -

(a) improving line maintenance practices;

(b) improving protection and breaker operating times;

(c) replacing the said equipment if necessary;

(d) installing additional network breakers;


(e) changing operating procedures; and

(f) installing fault-limiting devices if the number of faults cannot be reduced.

(4) The steps contemplated in subcode (3) must be effected in consultation with the transmission company on both the technical scope and the time frame.

(5) Where quality of supply standards is transgressed, the parties must co-operate and agree in determining the root causes and plans of action.

Delivered quality of supply of transmission company

71. (1) Quality of supply is -

(a) a shared responsibility between the transmission company and its customers; and

(b) based on Namibian Quality of Supply and Service Standards as agreed with all stakeholders.

(2) The transmission company must agree in writing with its customers, for every point of supply, on the following quality of supply parameters, taking local circumstances, historical performance and the relevant standards into account:

(a) interruption performance;

(b) voltage regulation performance;

(c) dip performance;

(d) total harmonic distortion performance;

(e) flickerperformance;

(f) unbalance performance; and

(g) customer responsibilities in terms of harmonic current injection, unbalanced currents and addition of voltage dips to the network.

(3) A reasonable time period for monitoring performance must be allowed before performanceisagreedtoforthefirsttimeintermsofinterruptionsanddips.

(4) The time period contemplated in subcode (3) is three years unless otherwise agreed.

(5) For harmonic voltages and voltage unbalance, performance can be monitored after one week if measurements are done.

(6) Where a transmission company fails to meet the agreed upon quality of supply parameters contemplated in subcode (2)(b), the transmission company must take reasonable steps at own cost to overcome the shortcomings, by -

(a) improving line maintenance practices;

(b) improving protection and breaker operating times;

(c) replacing the said equipment if necessary;


(d) installing additional network breakers;

(e) changing operating procedures; or

(f) installing fault-limiting devices if the number of faults cannot be reduced.

(7) The steps contemplated in subcode (6) must be effected in consultation with the customer on both the technical scope and the time frame.

Equipment requirements

72. (1) Where a distributor or end-use customer needs to install equipment that connects directly with transmission company equipment in transmission substations, the equipment must adhere to the transmission company technical design requirements contemplated in codes 74 to 85 inclusive.

(2) The transmission company may require customers to provide documentary proof that their connection equipment complies with all relevant standards, both by design and by testing.

(3) A distributor or end-use customer who intends to install a new series capacitor or modify the size of an existing series capacitor must, at own expense and according to the requirements of the transmission company, arrange for sub synchronous resonance, harmonic and protection coordination studies to be conducted to ensure that sub synchronous resonance will not be excited in any generator.

PART 2TRANSMISSION SYSTEM TECHNICAL REQUIREMENTS

Purpose of transmission company technical design requirements

73. The purpose of the transmission company technical design requirements contemplated in codes 74 to 85 inclusive, is to document the design and other technical standards that the transmission company must adhere to.

Equipment design standards

74. (1) Primary substation equipment must comply with International Electro-technicalCommission(IEC)specifications.

(2) The application of the specifications contemplated in subcode (1)must cater forlocal conditions including increased pollution levels and must be determined by or in consultation with the customer.

(3) The transmission company must design, install and maintain equipment in accordance with relevant electricity industry standards.

(4) Customers may require the transmission company to provide documentary proof that their connection equipment complies with all relevant standards, both by design and by testing.

Clearances

75. Clearances must comply with relevant electricity industry standards.

Current Transformer (CT) and Voltage Transformer (VT) ratios and cores

76. Current Transformer and Voltage Transformer ratios and cores must be determined


by or in consultation with the transmission company.

Standard busbar arrangements and security criteria

77. Substationsonthetransmissionsystemmustbeconfiguredinaccordancewithcode78 and 79.

Transmission substation standard busbar arrangements

78. (1) The reliability and availability of the transmission system is dependent on, but not limited to -

(a) transmission system lines;

(b) transformers;

(c) other primary and secondary plants; and

(d) the busbar layout.

(2) When planning the transmission system, the transmission company must prudently assess the busbar layout contemplated in subcode (1)(d) and assess what the busbar layout can do for the reliability and availability of the supply of the customer.

(3) When planning substation design, the transmission company must base the standard busbar arrangement on providing one busbar zone for every main transformer line normally supplying that busbar.

(4) A transmission company must consider the local conditions, type of equipment used, type of load supplied and other factors in the assessment of the required busbar redundancy.

(5) The system reliability criteria set out in code 138 must also be adhered to in addition to subcodes (1) to (4).

Use of bypasses

79. (1) Bypasses provide high line availability by allowing circuit breakers to be taken out of service for maintenance and testing without affecting line availability.

(2) The bypass with single busbar selection must be used at 220 kV on single line radial feeds to provide continuity of supply when maintaining the line breakers.

(3) The bypass with double busbar selection must be used on new 400 kV, 330 kV lines and220kVlineswherejustified.

Motorised isolators

80. To provide motorised isolators at new substations -

(a) all 400 kV, 330 kV and 220 kV isolators must be motorised at new substations; and

(b) isolatorsof132kVandbelowmustbe specifiedon individualmerit, taking into


account importance ranking, cost and remoteness.

Earthing isolators

81. Earthing isolators must be provided at new substations where the fault level is designed for 20 kA and above.

Busbar protection Current Transformers (CT’s)

82. (1) For phase 3 busbar protection schemes, single sets of Current Transformers, including 3 CT’s instead of 6 CT’s, must be used on bus couplers and bus section breakers to reduce the probability of a double bus zone outage for a CT fault on a bus coupler or bus section breaker.

(2) At power station, overlapped bus zones must be retained to ensure fastest possible clearance of busbar faults.

Tele-control

83. (1) Either participant may be permitted to have tele-control equipment in the substations, yards or buildings of the other party, to perform agreed monitoring and control and access must be provided to the tele-control equipment.

(2) Distributors must have reliable Supervisory Control and Data Acquisition (SCADA) facilities including telecommunications, computers and remote terminal units for the distribution system connected directly to the transmission system, to provide the necessary response where system conditions require.

Transformer tap change

84. (1) The transmission company must install automatic tap changing facilities on all new transformers.

(2) Transformers used in the transmission system at 220kV or more are normally not on automatic tap change and transformers supplying a customer are usually on automatic tap change.

(3) Voltage levels, sensitivity and time settings and on or off auto tap changing must be determined by the -

(a) system operator in consultation with the customer; and

(b) transmission company.

Substation drawings

85. The following set of drawings must be made available by the respective asset owners for all points of supply, if required by the other party for the purposes of connection:

(a) station electric diagram;

(b) key plan;

(c) bay layout schedules;

(d) foundation, earth mat and trench layout;

(e) steelwork marking plan;


(f) security fence layout;

(g) terrace, road and drainage layout;

(h) transformer plinth;

(i) general arrangement;

(j) sections;

(k) slack span schedule;

(l) barrier fence layout;

(m) security lighting;

(n) floodlightingparametersketch;

(o) protection details; and

(p) contour plan.

Protection requirements

86. (1) Codes 87 to 123 specify the minimum protection requirements for a transmission company as well as typical settings, to ensure adequate performance of the transmission system as experienced by the customers.

(2) The transmission company must at all times install and maintain protection installations that comply with the provisions of the codes contemplated in subcode (1).

(3) The transmission company must conduct periodic testing of equipment and systems toensureanddemonstratethattheequipmentandsystemsareperformingtothedesignspecifications.

(4) Testsproceduresmustbeaccordingtothespecificationsofthemanufacturer.

(5) The transmission company must make available to customers all results of test performed on equipment for reasonable requests.

(6) Protection schemes are generally divided into -

(a) equipment protection; and

(b) system protection.

Protection design standards for equipment (feeder protection: 220kV and above)

87. (1) New feeders must be protected by the Main 1 and Main 2 protection systems.

(2) The Main 1 and Main 2 protection systems must be fully segregated in secondary circuits.

(3) An additional earth fault function must be incorporated in the main protection relaysorinstalledseparatelytoalleviatepossibledeficienciesofdistancerelaysindetectionofhighresistance faults.


Protection settings for equipment (feeder protection: 220kv and above)

88. (1) The protection relays -

(a) must provide reliable protection against all possible short circuits;

(b) must provide remote or local back up for not cleared busbar faults; and

(c) are not set to provide overload tripping.

(2) Wherespecificallyrequired,thefeederprotectionmaybeset,ifpossible,toprovideremote back up for other faults as agreed upon with other participants.

Automatic reclosing for equipment (feeder protection: 220kV and above)

89. (1) Automatic reclosing facilities must be provided on all feeders.

(2) The system operator must decide on automatic reclosing selection based on real time system, environmental constraints and consultation with customers, with regard to equipment capabilities and in accordance with codes 90 to 93.

(3) All automatic reclosing settings and methodology must be -

(a) implemented by the transmission company; and

(b) made available by the transmission company to customers on request.

Automatic reclosing cycles (ARC) for equipment (feeder protection: 220kV and above)

90. (1) Either of the following two automatic reclosing cycles for single phase faults must be used:

(a) double attempt ARC cycle for persistent fault: 1ph fault – 1ph trip – 1ph ARC – 3ph trip – 3ph ARC – 3ph trip – lockout; or

(b) single attempt ARC cycle for persistent fault: 1ph fault – 1ph trip – 1ph ARC – 3ph trip – lockout.

(2) The ARC cycle for a multiphase (mph) fault must be: mph fault – 3ph trip – 3ph ARC – 3ph trip – lockout.

(3) On some lines the automatic reclosing is being switched off according to the following operational needs:

(a) sporadically, when high risk of line fault is recognised, for live line work or to reduce breaker duty cycle where the condition of the breaker is questionable;

(b) periodically, during season of high fault frequency;

(c) permanently, on lines with the highest fault frequency throughout the year or on the request of the customers; or

(d) whenever an automatic reclosing could initiate a severe power swing or an Out-Of-Step condition in weakly interconnected systems.

Single phase automatic reclosing


91. (1) In most applications the dead time of single phase automatic reclosing is

selected to one second but may differ for different system requirements.

(2) The closing of the breaker is performed without synchronisation as the synchronism is maintained via remaining phases that are closed during the whole incident.

Three phase automatic reclosing (fast ARC)

92. (1) Fast automatic reclosing or the fast closing of the breaker without checking synchronism, is not used on the transmission system to avoid stress to the rotating machines at the power stations and at the plant of the customer but is available on protection panels and can be selected in case of an emergency such as when as a result of outages disturbance load or generation islands are interconnected via a single line.

(2) Despite subcode (1) the operating practice is to use only single phase automatic reclosing (fast by its nature) as a compromise between supply reliability and stress to the equipment.

Three phase automatic reclosing (slow ARC)

93. (1) The dead line charging (DLC) end is selected in line with the Table 1 in Annexure 6 based on fault level at the connected substations A and B.

(2) In most applications the dead time of slow automatic reclosing is selected to three seconds at dead line charging (DLC) end of the line.

(3) At the synchronising end of the line the automatic reclosing dead time is usually selected to four seconds.

(4) The close command will be issued only after synch-check is completed and this may take up to two seconds if synchronising relays are not equipped with direct slip frequency measurement.

(5) The breaker may take longer to close if its mechanism is not ready to close after initial operation at the time when the close command is issued.

(6) On the line between two power stations the dead time at the dead line charging (DLC) end should be extended to 25 seconds to allow the rotors oscillations of the generator to stabilise.

(7) The dead time on the synchronising end is then extended accordingly to 30 seconds.

(8) Thesynchronisingrelaysareinstalledatbothendsofthelinetoenableflexibilityinautomatic reclosing cycles and during restoration.

Power swing blocking

94. (1) New distance relays on the transmission system must be equipped with power swing blocking facility.

(2) All unwanted operations of distance relays during power swing conditions must be blocked on the transmission system.

Design standard: equipment protection requirements (feeder protection: 132kV and below at transmission company substations)


95. (1) The feeders of 132 kV and lower must be protected by a single protection system, incorporating either distance or differential protection relays, unless otherwise agreed.

(2) Back up must be provided by definite time and inverse definite minimum time(IDMT) over-current and earth fault relays.

(3) The protection must be equipped with automatic reclosing.

(4) Synchronising relays must be provided on feeders that operate in “ring supplies” and are equipped with line voltage transformers.

Protection settings: equipment protection requirements (feeder protection: 132kV and below at transmission company substations)

96. (1) Protection relays -

(a) must provide reliable protection against all possible short circuits;

(b) must provide remote and local back up for un-cleared busbar faults; and

(c) should not be set to provide overload tripping where measurements and alarms are provided on Supervisory Control and Data Acquisition (SCADA) system.

(2) In isolated applications where Supervisory Control and Data Acquisition (SCADA) system is not available, overload tripping will be provided.

(3) Where overload conditions are alarmed at control centres, it is the responsibility of the control centre to reduce load to an acceptable level as quickly as possible.

Automatic reclosing: equipment protection requirements (feeder protection: 132kV and below at transmission company substations)

97. (1) The customer must determine automatic reclosing requirements.

(2) The system operator may specify additional automatic reclosing requirements for system security reasons, which could extend beyond the transmission company substations.

Tele-protection requirements

98. New distance protection systems must be equipped with tele-protection facilities to enhance the speed of operation.

Transformer and reactor protection

99. (1) The standard schemes for transformer protection comprise a number of systems, each designed to provide the requisite degree of protection for the following fault conditions:

(a) faults within the tank;

(b) faults on transformer connections;

(c) overheating;

(d) faults external to the transformer; and


(3) The transmission company must consider the application of the relays contemplated in codes 100 to 106 inclusive, in the design of the protection system.

Transformer Inverse Definite Minimum Time Earth Fault

100. The medium voltage earth fault protection is to discriminate with the feeder back-up earth fault protection for feeder faults

Transformer HV/MV Inverse Definite Minimum Time Over-Current

101. (1) Thesystemoperatorrequiresthattheinversedefiniteminimumtimeover-current (IDMT O/C) does not operate for twice transformer full load.

(2) Overloading of the transformer is catered for by the winding and oil temperature protection but network requirements may be such that subcode (1) cannot be applied and a mutually agreed philosophy may have to be used.

Transformer HV/MV instantaneous Over-Current

102. Transformer high voltage medium voltage instantaneous over-current (Transformer HV/MV instantaneous Over-Current) back-up protection caters for flash-overs external to thetransformer on the HV side or MV side and should operate for minimum fault conditions (possibly as well for an Earth Fault condition). However, the overriding requirement is not to operate for through faults or for magnetising inrush current.

Transformer LV (tertiary) Inverse Definite Minimum Time /instantaneous Over-Current

103. This protection is to operate for external faults between the main delta winding of the transformer and the auxiliary transformer, but not for faults on the secondary side of the auxiliary transformer. The auxiliary transformer is protected by buchholz and temperature protection.

Transformer current differential protection

104. (1) Transformer current differential protection is the main transformer protection for earth fault and phase to phase faults.

(2) Maximum sensitivity is required, while ensuring no incorrect operation for load, for through fault conditions or for magnetising inrush current with its attendant decaying offset.

Transformer high impedance restricted Earth Fault

105. Transformer high impedance restricted earth fault is an additional protection for the transformer differential relay to cater for earth faults close to the star point of the transformer winding, where phase to phase faults are most unlikely to occur.

Transformer thermal overload

106. Winding temperature and oil temperature relays, supplied by the manufacturer are used to prevent transformer damage or life time reduction due to excessive loading for the ambient temperature or during failure of the cooling system.

Transmission system busbar protection

107. Busbars must be protected by current differential protection (bus-zone) set to be as sensitive as possible for the in-zone faults and maintain stability for any faults outside the protected


zone, even with fully saturated current transformer.

Transmission system bus coupler and bus section protection

108. Bus-coupler and bus-section panels are equipped with over-current and earth fault protection.

Transmission system shunt capacitor protection

109. (1) All the new high voltage capacitor banks must be equipped with sequence switching relays to limit inrush current during capacitor bank energisation. Inrush reactors and damping resistors must also be employed to limit inrush current.

(2) The following protection functions must be provided for all types of protection schemes:

(a) unbalanced protection with alarm and trip stages;

(b) over-currentprotectionwithinstantaneousanddefinitetimeelements;

(c) earthfaultprotectionwithinstantaneousanddefinitetimesensitivefunction;

(d) overloadprotectionwithinversedefiniteminimumtimecharacteristic;

(e) over-voltagewithdefinitetime;

(f) circuit breaker close inhibit for 300 seconds after de-energisation; and

(g) ancillary functions as indicated below.

Over-voltage protection

110. (1) Primary protection against high transient over-voltages of magnitudes above 140% must be provided by means of surge arrestors.

(2) To curtail dangerous, fast developing over-voltage conditions that may arise as a result of disturbance, additional over-voltage protection must be installed on shunt capacitors and feeders.

(3) Over-voltage protection on shunt capacitors is set to disconnect capacitor at 110% voltage level with a typical delay of 200 milliseconds to avoid unnecessary operations during switching transients.

(4) Over-voltage protection on the feeders is set to trip the local breaker at voltage level of 120% with a delay of one to two seconds.

Ancillary protection functions

111. (1) Protection systems are equipped with auxiliary functions and relays that enable adequate co-ordination between protection devices and with bay equipment.

(2) The transmission company must consider the functions contemplated in codes 112 to 116 inclusive, for all new protection system designs.

Breaker fail or bus trip

112. Each individual protection scheme is equipped with breaker fail or bus trip function


to ensure fast fault clearance in case of circuit breaker failure to interrupt fault current.

Breaker pole discrepancy

113. (1) Breaker pole discrepancy protection compares, by means of breaker auxiliary contacts, state (closed or opened) of breaker main contacts on each phase.

(2) When breaker on one phase is in a different position than breakers on remaining phases a trip command is issued after time delay.

Breaker anti-pumping

114. (1) To prevent repetitive closing of the breaker in case of fault in closing circuits the standard Protection schemes provide breaker anti pumping timer.

(2) Circuit breakers are often equipped with their own anti pumping devices and the anti pumping function is duplicated.

Pantograph isolator discrepancy

115. The pantograph isolator discrepancy relay operates in the same manner as breaker pole discrepancy and is used to issue local and remote alarm.

Master relay

116. (1) Transformer and reactor protection schemes are equipped with latching master relay that require manual reset before the circuit breaker is enabled to close.

(2) The master relay is operated by unit protection that indicates possibility of internal failure.

System protection requirements (under-frequency load shedding)

117. (1) The actions taken on the power system during an under-frequency condition are set out in Chapter 4.

(2) Under-frequency load shedding relays must be installed in the interconnected power system as determined by the system operator in consultation with distributors and end-use customers.

(3) An asset owner must pay for the installation and maintenance of the relays referred to in subcode (2).

(4) The system operator must periodically test under-frequency relays.

(5) Distributors and end-use customers must submit to the system operator a written report of each test referred to in subcode (4) within a month of the test being done and in the format specifiedincode230(2).

(6) The test referred to in subcode (4) must be done by isolating all actual tripping circuits, injecting a frequency to simulate a frequency collapse and checking all related functionality.

System protection requirements (out of step tripping)

118. (1) The purpose for the out-of-step tripping protection is to separate power system in a situation where a loss of synchronous operation takes place between a unit or units and


the main power system.

(2) In a situation referred to in subcode (1), system separation is desirable to remedy the situation.

(3) Once the islanded system is stabilised it can be reconnected to the main system.

(4) The system operator must determine and specify the out-of step tripping functionality to be installed at selected locations by the transmission company.

System protection requirements (Under-voltage load shedding)

119. (1) Under-voltage load shedding protection schemes are used to prevent loss of steady-state stability under conditions of large local shortages of reactive power (voltage collapse). Automatic load shedding tripping of suitable loads is carried out to arrest the slide.

(2) The system operator must determine and specify the under-voltage load shedding functionality to be installed at selected locations by the transmission company.

System protection requirements (sub-synchronous resonance protection)

120. (1) The sub-synchronous resonance condition may arise on a power system where a generator is connected to the main power system through long series compensated transmission system lines.

(2) The potential for unstable interaction is sensitive to system topology and is greater with the higher degree of compensation and larger thermal turbo-generators are employed.

(3) The sub-synchronous resonance condition is addressed either through protection or mitigation and if through -

(a) protection -

(i) a suitable relay must be deployed as part of the turbo-generator protection that will lead to the unit disconnection on detection of the sub-synchronous resonance condition; and

(ii) the protection does not reduce or eliminate the torsional vibration, but rather detects it and acts to remove the condition leading to the resonance; or

(b) mitigation, the mitigation -

(i) acts to reduce or eliminate the resonant condition; and

(ii) is needed only under conditions when it is desirable or essential to continue operation when the power system is at or near a resonant condition.

(4) A new generator must liaise with the transmission company regarding sub-synchronous resonance protection studies.

(5) Least-cost solutions must be determined by the transmission company in accordance with code 147 and implemented by the relevant asset owner.

System protection requirements (protection against near 50 Hz resonance)

121. (1) Due to the length of the transmission system network in Namibia and due


to the relatively low load conditions, a near 50 Hz resonance may arise on the transmission system network.

(2) Adequate reactive compensation for purposes of subcode (1) need to be installed onthetransmissionsystemandtheinfluenceofthesystemoperatorandclientsonthisnear50Hzresonance needs to be reduced.

(3) The transmission company must ensure that the near 50 Hz resonance is catered for in any old or new networks.

System protection requirements (protection settings impact on network stability (dynamic stability))

122. Minimum clearance times for protection in distributor or end-use customer networks will be determined on a case by case basis in order to ensure dynamic stability of the transmission system.

Protection system performance monitoring

123. (1) To maintain high level of protection performance and long term sustainability, the Transmission company must monitor protection performance.

(2) Each protection operation must be investigated for its correctness based on available Information.

(3) The transmission company must provide a report to customers affected by a protection operation when requested to do so.

Nomenclature

124. All safety terminology must comply with the transmission company operating regulations for high voltage systems.

PART 3TRANSMISSION SYSTEM PLANNING AND DEVELOPMENT

Transmission system planning and development

125. (1) Codes 126 to 155 sets out the -

(a) technical, design and economic criteria and procedures to be applied by the transmission company in the planning and development of the transmission system and to be taken into account by customers in the planning and development of their own systems; and

(b) information to be supplied by customers to the transmission company, and information to be supplied by the transmission company to customers.

(2) The development of the transmission system, will arise for a number of reasons including, but not limited to -

(a) a development on a customer system already connected to the transmission system;

(b) the introduction of a new transmission system substation or point of connection or themodificationofanexistingconnectionbetweenacustomerandthetransmission


system;

(c) the cumulative effect of a number of the developments referred to in paragraphs (a) and (b) by one or more customers; and

(d) theneedtoreconfigure,decommissionoroptimisepartsoftheexistingnetwork.

(3) The development of the transmission system as contemplated in subcode (2) may involve work -

(a) at a substation where a plant or apparatus of a customer is connected to the transmission system;

(b) on transmission system lines or other facilities which join the substation referred to in paragraph (a) to the remainder of the transmission system; or

(c) on transmission system lines, transmission system substations or other facilities at or between points remote from that substation.

(5) The time required for the planning and development of the transmission system will depend on -

(a) the type and extent of the necessary reinforcement or extension work;

(b) the need or otherwise for statutory planning consent;

(c) the associated possibility of the need for public participation; and

(d) the degree of complexity in undertaking the new work while maintaining satisfactory security and quality of supply on the existing transmission system.

Planning process

126. The transmission company must follow a planning process divided into major activities as follows:

(a) needsidentification;

(b) formulation of alternative options to meet this need;

(c) studying these options to ensure compliance with agreed technical limits, and justifiablereliabilityandqualityofsupplystandards;

(d) costing these options on the basis of present-day capital costs and using appropriate net discount rates, establish the net present cost of each option;

(e) determining the preferred option;

(f) building a business case for the preferred option using acceptable justificationcriteria; and

(g) requesting approval of preferred option and initiating execution.


Identification of need for transmission system development

127. The transmission company must source relevant data from relevant national planning studies,specificcustomerinformation,governmentalandcustomerdevelopmentplanstoestablishthe needs for network strengthening.

Forecasting demand

128. (1) The transmission company is responsible for producing the transmission systemdemandforecastforthenextfiveyearsandupdatingitannuallyandforestimatingtheloadforecast for the next 10 years.

(2) The transmission system demand forecast must be determined for each point of supply.

(3) Generation and import capacity plans must be used to obtain the annual generation patterns.

(4) To forecast the maximum demand megawatt for each transmission system substation, the transmission company must -

(a) use distributor and end-use customer load forecasts; and

(b) reconcilefinalloadswithdatafromvarioussources.

(5) Load forecasts must be adjusted at various levels, by making use of diversity factors determined from measurements and calculations, to line up with the higher-level data.

(6) All distributors and end-use customers must annually, by end October, supply their fiveyear ahead load forecast data and an estimate for the10years aheaddemandasdetailed inChapter 6.

Technical limits and targets for planning purposes

129. (1) The limits and targets against which proposed options are checked by the transmission company must include technical and statutory limits which must be observed and other targets which indicate that the system is reaching a point where problems may occur.

(2) If technical or statutory limits are not achieved, alternative options shall be evaluated.

(3) If targets are not achieved, some options may be still acceptable as per the investment criteria.

Voltage limits and targets

130. (1) The technical and statutory voltage limits are as set out in Table 2 of Annexure 3.

(2) The standard voltage levels are as set out in Table 3 of Annexure 3.

(3) The target voltages for planning purposes are as set out in Table 4 of Annexure 3.

Other targets for planning purposes


131. The other targets for planning purposes are as set out in codes 132 to 137 inclusive.

Transmission system lines

132. (1) Thermal ratings of standard transmission system lines must be determined and updated from time to time.

(2) The temperatures used are 90ºC for aluminium conductor steel reinforced lines providingafirmsupply,undersinglecontingenciesand75ºCforlinesofcopperoraluminiumalloyoraluminiumconductorsteelreinforcedlinesnotprovidingafirmsupply.

(3) The thermal ratings must be used as an initial check of line overloading.

(4) If the limits of the thermal ratings are exceeded the situation must be investigated as it may be possible to defer strengthening depending on the actual line and on local conditions.

Transformers

133. (1) Standard transformer ratings must be determined and updated from time to timeusingInternationalElectro-technicalCommission(IEC)specifications.

(2) Thepermissibleoverloadofaspecifictransformerdependsonloadcycle,ambienttemperature and other factors.

(3) If target loads are exceeded, the specific situation must be assessed as it maybe possible to defer adding extra transformers, depending on the actual transformer and on load conditions.

Series capacitors

134. (1) With the system healthy, the maximum steady state current should not exceed the rated current of the series capacitor.

(2) IEC 143 standards call for cyclic overload capabilities as follows:

(a) 8 hours in a 12-hour period, 1.1 times rated current;

(b) ½ hour in a 6 hour period, 1.35 times rated current; and

(c) 10 minutes in a 2 hour period, 1.5 times rated current. (3) Despite subcode (2) the transmission company may require an occasional over-

current rating of two hours once per year 1.3 times rated current.

(4) The particular rating to be used must match the duration of the contingency with the required overload capability.

(5) Duration of contingency will depend on ability to pick up generation or shed load andtheloadprofile.

(6) If a transmission company intends to install a new series capacitor or modify the size of an existing series capacitor, the transmission company must at own expense and according to its requirements, arrange for sub synchronous resonance, harmonic and protection coordination studies to be conducted to ensure that sub synchronous resonance will not be excited in any generator.

Shunt reactive compensation


135. (1) Shunt capacitors must be able to operate at 30 percent above their nominal rated current at Un to allow for harmonics and voltages up to Um.

(2) Reactivecompensation,whethernewormodified,maycauseharmonicresonanceproblems.

(3) A participant wishing to install or modify reactive power compensation must at his expense arrange for harmonic resonance studies to be conducted.

(4) If the studies referred to in subcode (2) indicate possible harmonic resonance conditions which could impact on the transmission system the participant must inform the system operatorbeforeproceedingwiththeinstallationormodification.

Circuit breakers

136. (1) Normal and fault current ratings for standard switchgear are determined and updated from time to time.

(2) Theratingscontemplatedinsubcode(1)andthefollowinglimitsspecifiedforcircuitbreakers must not be exceeded:

(a) Single-phase breaking current, 1.15 times three phase fault current; or

(b) Peak making current, 2.55 times three phase rms fault current.

Secondary automatic reclosing cycle current during single-phase re-closing

137. The secondary automatic reclosing cycle current must not exceed:

(a) 20 amps rms with recovery voltage of 0.4 pu; or

(b) 40 amps rms with recovery voltage of 0.25 pu.

Reliability criteria for planning purposes

138. (1) A system cannot be made 100% reliable as planned, forced outages of components will occur and multiple outages are always possible, despite having a very low probability of occurrence.

(2) From an economic point of view optimum reliability is obtained when the cost involved in reducing the load not supplied by one kW is just equal to the value of this unsupplied kW totheeconomyortothespecificcustomerinvolved.

(3) The appropriate degree of reliability depends on the probability of loss of supply and the probable amount of load not supplied when an outage does occur.

(4) The transmission company must formulate long-term plans for expanding or strengtheningthetransmissionsystemonthebasisofthejustifiableredundancy.

Contingency criteria for planning purposes

139. (1) A system meeting the n-1 or n-2 contingency criterion must comply with the limits referred to in code 130.


(2) For contingencies under various loading conditions it must be assumed that appropriate, normally-used, generating plant is in service to meet the load and provide spinning reserve.

(3) The availability of the Ruacana Power Station will be taken into account for all load flowstudies.

(4) A generation condition at Ruacana will not be one of the base cases used in planning studies.

(5) For the more probable n-1 network contingency the most unfavourable generation pattern within the limitations referred to in subcodes (1) to (4) must be assumed, while for the less probable n-2 network contingency an average pattern must be used.

(6) Moredetailsofloadandgenerationassumptionsforloadflowstudiesaresetoutincode 140.

(7) The generation assumptions for the n-1 and n-2 network contingencies do not affect thefinaljustificationtoproceedwithinvestments,butmerelycheckthatthebackboneofthenetworkisstillsufficienttomeetann-1orn-2contingency.

Integration of power stations

140. When planning the integration of power stations the criteria contemplated in codes 141 to 145 inclusive, applies.

Power stations of less than 1000 MW

141. (1) With all connecting lines healthy, it must be possible to transmit the total output of the power station to the system for any system load condition.

(2) If the local area depends on the power station for voltage support, connection must be done with a minimum of two lines.

(3) Transient stability must be maintained following a successfully cleared single phase faultwhereeconomicallyjustifiable.

(4) If only a single line is used it must be able to be selected to alternative busbars and be able to go on to bypass at each end of the line

Power stations of more than 1000 MW

142. (1) With one connecting line out of service (n-1) it must be possible to transmit the total output of the power station to the system for any system load condition

(2) With the two most onerous line outages (n-2) it must be possible to transmit 83% of the total output of the power station to the system

Transient stability

143. (1) Transient stability must be retained for the following conditions -

(a) a three-phase, line or busbar fault, cleared in normal protection times, with the system healthy and the most onerous power station loading condition;


(b) a single phase fault cleared in bus strip times, with the system healthy and the most onerous power station loading condition; or

(c) a single-phase fault, cleared in normal protection times, with any one line out of service and the power station loaded to average availability.

(2) The conditions contemplated in subcode (1) apply only to power stations larger than 1000 MW, for power stations smaller than 1000 MW, the conditions will only apply where it is economicallyjustifiable.

(3) A transmission company bears the cost to ensure transient stability and must recover the costs as per the approved tariff methodology.

(4) Despite subcode (3), a generator bears the cost to ensure transient stability if the optimum solution, as determined by the transmission company, results in unit or power station equipment to be installed.

Busbar arrangements

144. Busbar layouts must allow for selection to alternative busbars and the ability to go on to bypass, and not more than 1000 MW of generation must be connected to any bus section, even with one bus section out of service.

Information required

145. To enable the transmission company to successfully integrate new power stations, detailed information is required per unit and power station, as contemplated in Chapter 6.

Criteria for network investments

146. (1) The planning limits, targets and criteria form the basis for evaluation of the long-term development of the transmission system.

(2) The transmission company must -

(a) only invest in the transmission system when the required development meets the approvedinvestmentcriteriaspecifiedinsubcode(5);and

(b) invest as contemplated in paragraph (a) if the development meets the approved criteria, but the transmission company may agree with affected customers to waiver certain investments.

(3) Any one of the investment criteria set out in subcodes 4 and 5, each applicable under different circumstances, can be applied.

(4) Calculations will assume a typical project life expectancy of 25 years except where otherwise dictated by plant life or project life expectancy.

(5) The following key economic parameters must have a Board approved process of being established:

(a) discount rate; and

(b) Cost of unserved energy.


Least economic cost criteria

147. (1) The least economic cost criteria may be used -

(a) when investments are made in terms of improved supply reliability or quality; or

(b) to determine or verify the desired level of network or equipment redundancy.

(2) The least economic cost criteria requires -

(a) the determination of the cost of poor network services including the cost of interruptions, load shedding, network constraints and poor quality of supply; and

(b) statistical analysis of network outages.

(3) The least-cost investment criterion equation to be satisfied can be expressed as:Value of improved quality of supply to customers > Cost to the service provider to provide improved quality of supply.

(4) If a project is proposed and pursuant to subcode (1)(a) a service provider uses the equation in subcode (2), the service provider should not invest in the proposed project if the value of the improved quality of supply to the customer is less than the cost to the service provider to improve the quality of supply.

(5) Equation above can be stated differently as: Annual value (N$/kWh) x Reduction in expected energy not served to Consumers (kWh) > Annual cost to the service provider to reduce expected energy not served (R).

(6) For purposes of subcode (4) -

(a) the reduction in expected energy not served is calculated on a probabilistic basis based on the improvements derived from the investments; and

(b) the cost of unserved energy is a function of -

(i) the type of load;

(ii) the duration and frequency of the interruptions;

(iii) the time of the day the interruptions referred to in subparagraph (ii) occur;

(iv) whether notice is given of the impending interruption;

(v) the indirect damage caused;

(vi) the start-up costs incurred by the consumers;

(vii) the availability of customer back-up generation; and

(viii) many other factors.

Cost reduction investments

148. (1) Proposed expenditure which is intended to reduce the costs -


(a) to service providers, of but not limited to -

(i) shunt capacitor installations;

(ii) telecommunication projects and telecommunication replacement equipment which reduce costs; and

(iii) external telephone service expenses and maintenance costs; or

(b) of losses or other ancillary services,

should be evaluated in the manner set out in subcode (2).

(2) For purposes of the evaluation contemplated in subcode (1) -

(a) it is necessary to calculate the net present value of the proposed investment using the discountedcashflowmethod;

(b) the calculation referred to in paragraph (a) should be done by considering all cost reductionsincludingsavingsinsystemlosses,aspositivecashflowsoff-settingtherequired capital expenditure;

(c) sensitivity analysis is required with respect to the -

(i) amount of capital expenditure, including estimated contingency amount;

(ii) annual average incremental cost of generation, where appropriate; and

(ii) future load growth scenarios; and

(d) if the calculation under paragraphs (a) and (b) or the sensitivity analysis under paragraph(c)resultsinapositivenetpresentvalue,theinvestmentisjustifiedoverthe expected life of the proposed new asset.

Statutory or strategic investments

149. (1) Decisions on statutory or strategic investments need to be taken in order to encourage development in Namibia.

(2) Projects relating to statutory or strategic investments include the following:

(a) investments formally requested by government, including investments that will allow Namibiatobecomemoreself-sufficientinelectricitysupplyandissuespertainingtotheelectrificationofNamibia;

(b) increased connection with neighbouring countries and SAPP requirements to allow the electricity industry of Namibian access to other markets;

(c) projects necessary to meet environmental legislation, for example the construction of oil containment dams;

(d) expenditure to satisfy the requirements of the Labour Act, 2007 (Act No. 11 of 2007) andspecificallytheRegulationsrelatingtoHealthandSafetyofEmployeesatWorkpublished under Government Notice No. 1617 of 1 August 1997;

(e) possible compulsory contractual commitments; or


(f) servitude acquisition.

(3) Subcode (2)(d) is intended to ensure the safety of operating and maintenance personnel who are exposed to possible danger when busy with activities related to electricity transmission.

(4) Subcode(2)mustnotbeusedforjustifyingprojectsthatarenotofeconomicbenefit.

Development investigation reports

150. (1) The transmission company must compile, before any development of the transmission system is approved, a detailed development investigation report.

(2) The report referred to in subcode (1) must be used as the basis for making the investment decision and must as a minimum contain the following elements:

(a) a description of the problem or request;

(b) alternatives considered, including non-transmission or capital;

(c) anevaluationofthelong-termcostsorbenefitsofeachalternativecontemplatedinparagraph (b); and

(d) detailed techno-economic justificationof theselectedalternativeaccording to theapproved investment criteria.

Transmission system master plan

151. (1) Thetransmissioncompanymustannuallypublishafiveyearaheadnetworkexpansion plan, indicating the major capital investments planned.

(2) The transmission company must base the network expansion plan contemplated in subcode (1) on -

(i) all customer requests received at the time of planning;

(ii) network load forecasting; and

(iii) projects initiated by the transmission company.

Mitigation of network constraints

152. (1) A transmission company must regularly review and resolve network constraints

(2) A transmission company must put in place around each constraint economically optimal plans involving investment, the purchase of the constrained generation ancillary service or other solutions.

Interfacing between participants

153. A transmission company must ensure regular interfacing with customers, regarding network development, with the objective to achieve overall optimal plans that ensure economically efficientinvestment.


Special customer requirements for increased reliability

154. (1) If a customer requires a more reliable connection than the one provided by the transmission company and the customer is willing to pay the total cost of providing the increased reliability, the transmission company must meet the requirements at the lowest overall cost.

(2) Customers paying extra for reliability should be able to recoup some of the expenses from other customers.

(3) The transmission company must include details regarding recovery of direct costs in its connection agreement with its customers, distributors or end-use customers.

Network maintenance

155. (1) A participant -

(a) must operate and maintain the equipment owned by the participant; and

(b) bears the costs of the operation and maintenance contemplated in paragraph (a) unless the participant proves that the equipment referred to in that paragraph was damaged by the negligent act or omission of another participant or a participant who is not -

(i) the owner of the equipment; or

(ii) an agent or employee of the owner referred to in subparagraph (i),

in which case the participant who is responsible for the damage is liable for the costs of repairing the damage.

(2) Participants must monitor the performance of their plant and take appropriate action where deteriorating trends are detected.

CHAPTER 4TRANSMISSION SYSTEM OPERATIONS

PART 1OPERATIONAL RELATIONS, PROCEDURES, PLANNING, CONDITIONS AND CONTROL

Operation of interconnected power system

156. (1) Thesystemoperatorisresponsibleforthesafeandefficientoperationoftheinterconnected power system.

(2) The system operator must operate the interconnected power system in accordance with the provisions of this code.

(3) All participants must co-operate in setting up operational procedures under the direction of the system operator to ensure proper operation of the interconnected power system.

(4) The system operator has ultimate authority and accountability for the operation of the interconnected power system.

(5) SAPP and other international tie-line operations must be governed by the SAPP and related agreements.


System operator obligations

157. The system operator is responsible for the -

(a) system reliability and safety contemplated in code 158;

(b) system security contemplated in code 159; and

(c) operational measures contemplated in code 160.

System reliability and safety

158. (1) The interconnected power system must be operated to achieve the highest degree of reliability practicable and appropriate remedial action must be taken promptly to relieve any abnormal condition that may jeopardise reliable operation.

(2) Power transfers as determined by the energy market or scheduling arrangements, and other transfers as far as feasible, must be adjusted as required to achieve or restore reliable interconnected power system operation.

(3) Voltage control, operating on the interconnected power system and security monitoring must be co-ordinated on a system - wide basis in order to ensure safe, reliable, and economic operation of the interconnected power system.

(4) During or after a system disturbance high priority must be given to keeping all synchronised units -

(a) running and connected to the interconnected power system; or

(b) islanded on their own auxiliaries,

in order to facilitate system restoration.

(5) Black start services must be provided as available from units.

(6) The system operator must make all reasonable endeavours to retain international interconnections unless it becomes evident that continued parallel operation of the affected parts of the interconnected power system would jeopardise the remaining system or damage equipment.

(7) Should it become unsafe to operate units in parallel with the system when critical levels of frequency and voltage result on the interconnected power system from a disturbance, the separation or safe shut down of units must be done in such a way as to minimize the time required to resynchronise and restore the system to normal.

(8) In the event of a system separation the system operator must ensure that the part of theinterconnectedpowersystemwithagenerationdeficitmustautomaticallyremovesufficientloadto permit early recovery of voltage and frequency so that system integrity may be re-established.

(9) Customer load must be shed for a reasonable period of time rather than risking the possibility of a cascading failure or operating at abnormally low frequency or voltage for an extended period of time.

(10) A system operator of an interconnected power system may request that the national system operator takes any available action to increase or decrease the active power transfer into or out of the local power system by the way of emergency assistance.


System security

159. (1) The interconnected power system must be operated as far as practical so that instability, uncontrolled separation or cascading outages do not occur as a result of the most severe double contingency.

(2) Multiple outages of a credible nature must be examined and whenever practical the interconnected power system must be operated to protect the interconnected power system against instability, uncontrolled separation and cascading outages.

(3) The system operator is responsible for efficient restoration of the transmissionsystem after supply interruptions.

(4) The system operator must operate and maintain primary and emergency control centres and facilities to ensure continuous operation of the interconnected power system.

Operational measures

160. (1) Operating instructions, procedures, standards and guidelines must be established to cover the operation of the interconnected power system under all system conditions.

(2) The interconnected power system must be operated within defined technicalstandards and equipment ratings.

(3) The system operator must manage constraints on the transmission system through the determination of operational limits and the purchase of the constrained generation ancillary service.

(4) To achieve a high degree of service reliability, the system operator must ensure adequate and reliable communications between all control centres, power stations and substations.

(5) Communicationfacilitiestobeprovidedandmaintainedbycustomersarespecifiedin code 217.

(6) The system operator is responsible for the determination of the transmission system protection philosophy, as contrasted to equipment protection, by means of applicable analytical studies.

(7) The system operator must determine, and review on a regular basis, relay settings for main and back-up protection on the interconnected power system.

Scheduling of generation and ancillary services

161. (1) The system operator must provide a day-ahead demand forecast for the interconnected power system.

(2) The single buyer must provide the system operator with the daily 24 hours day-ahead energy schedule from 16:00CAT each day.

(3) Should a deviation exist between the scheduled and actual load conditions the system operator is responsible for taking remedial action.

(4) A system operator is responsible for executing the energy schedule.


(5) A single buyer is responsible for scheduling ancillary services.

(6) A system operator is responsible for executing ancillary services.

(7) Rescheduling of generation and ancillary services during unplanned events must be undertaken by the system operator on the basis of rules provided by the single buyer.

Ancillary services

162. (1) The system operator is responsible for the technical specification andexecution of all short term reliability services for the interconnected power system.

(2) The short term reliability services referred to in subcode (1) include -

(a) restoration;

(b) the balancing of supply and demand;

(c) the provision of quality voltages; and

(d) the management of the real-time technical risk.

(3) Suitable ancillary service levels for the following year must be calculated annually.

(4) Reliability targets must be selected to minimise the sum of the cost to the transmission company of providing the reliability plus the cost to the customer of limited reliability.

(5) The single buyer is responsible for procuring the required ancillary services that are economicallyefficientandneededtoprovidetherequiredreliability.

(6) The acquisition of ancillary services must take place on a non-discriminatory basis.

Operating reserves

163. (1) Operating reserves are required to secure capacity that will be available for reliable and secure balancing of supply and demand.

(2) For purposes of subcode (1) there must be a spinning reserve, regulating reserve and quick reserve.

Spinning reserve

164. (1) The requirement is to keep the frequency above 49.5 Hz following all credible single contingency losses.

(2) ThecurrentrequirementisdefinedbytheAgreementBetweenOperatingMembersof the Southern African Power Pool.

Quick reserve

165. (1) A quick reserve -

(a) is a less frequently used reserve and is used when the interconnected power system is not in a normal condition;

(b) can be used for supply and demand balancing, network stability and voltage constraints; and


(c) must be activated, on request, within 10 minutes and must be sustainable for two hours.

(2) AminimumpowerasdefinedbytheAgreementBetweenOperatingMembersoftheSouthern African Power Pool is to be accepted for this reserve.

(3) Individual contracts may be aggregated into blocks executed as set out in Table 2 of Annexure 12.

(4) If individual contracts are aggregated as contemplated in subcode (3), each aggregated block must be contracted as one block.

(5) The quick reserve referred to in subcode (1) must also be under direct control from the system operator control centre.

(6) The requirements stated in subcodes (1) to (5), are due to the need to take quick action when abnormal conditions prevail on the system.

Regulating reserve

166. (1) The regulating reserve is used -

(a) for second-by-second balancing of supply and demand; and

(b) to restore instantaneous reserve within 10 minutes of a disturbance.

(2) The interconnected power system needs an amount of power as defined by theAgreement Between Operating Members of the Southern African Power Pool every hour to balance supply and demand and to keep the frequency and tie-lines within acceptable limits.

(3) The payment for moving up and down on automatic generation control is made under the regulation and load following ancillary service under code 169.

Black start and islanding

167. (1) Islanded units must be capable of running in the islanded state for at least two hours and of re-connecting to the network.

(2) Units capable of islanding must -

(a) offer service to the system operator; and

(b) becertifiedbythesystemoperatorandentitledtopaymentfortheservicereferredtoin paragraph (a).

(3) To ensure optimal operation of the interconnected power system, the system operator

may deploy network islanding schemes on the network, including an out-of-step tripping scheme.

(4) The system operator must determine the minimum requirements for each black start supplier and ensure that the contracted suppliers are capable of providing the service.

Reactive power compensation and voltage control from units

168. (1) Voltage control and the supply or consumption of reactive power is inter-relatedinthesensethatthevoltageisaffectedbychangesinthereactivepowerflow.


(2) Systemstabilitydependsonthevoltageprofileacrossthesystem.

(3) In view of subcodes (1) and (2), it is necessary from time to time to employ certain power stations to supply or consume reactive power whether or not they are producing active power, for the purpose of voltage control.

(4) The unit must be able to provide reactive power without having to produce or consume a large quantity of real power.

(5) The amount of reactive power must be controlled by the system operator through the energy management system or by telephone.

(6) When a unit is generating or pumping, reactive power supply is mandatory in the full operatingrangeasspecifiedincode39.

Regulation and load following

169. (1) The regulation and load following service is the automatic matching of supply and demand in real time by increasing or decreasing the active power of units.

(2) The control system for matching of supply and demand is called automatic generation control and it can send a command every four seconds to increase or decrease output.

(3) The unit of measure for determining payment is the number of megawatts moved by the supplier of the service in the hour.

Technical requirements of regulation and load following

170. (1) The resources contracted for the service of regulation and load following under code 169, must operate under automatic generation control and must be able to alter their generation or load under direct control of automatic generation control to the performance requirementsspecifiedbythesystemoperator.

(2) The requirement for the total capacity of regulation to be provided by the suppliers

oftheserviceofregulationandloadfollowingundercode169isspecifiedunderregulationreservein code 166.

(3) The requirement in subcode (2) is to meet the frequency and tie-line control standards asdefinedbythesystemoperatorandtheSouthernAfricanPowerPool.

Near 50 Hz resonance control service

171. (1) Some plant may be required to run in synchronous condenser mode in order to add fault level to the transmission system to mainly assist with the shifting of the near 50Hz resonance in the Namibian network upwards from 50Hz.

(2) The near 50Hz resonance control service is an additional risk mitigation option for the Auas Static VAR Compensator.

(3) Theplantsarerewardedfinanciallyforthesupplyofanear50Hzresonancecontrolservice.

Operational authority


172. (1) The system operator has operational authority over the transmission system.

(2) Operational authority for other networks lies with the respective asset owners.

(3) Normal control of the various networks must be in accordance with the operating procedures agreed between the participants.

(4) Unless otherwise provided in this Code, a participant may not be permitted to operate the equipment of another participant without the permission of that other participant.

(5) Before a participant is permitted to operate the equipment of another participant the asset owner has the right to test and authorise the operating staff in accordance with his or her own standards before the permission is granted.

(6) Despite subcode (1), participants retain the right to safeguard the health of their equipment.

Operating procedures

173. (1) The system operator must develop and maintain operating procedures for -

(a) the safe operating of the transmission system; and

(b) assets connected to the transmission system.

(2) The operating procedures referred to in subcode (1) must be adhered to by participants when operating equipment on the transmission system or connected to the transmission system.

(3) Each customer is responsible for his or her own safety rules and procedures.

(4) The system operator must ensure the compatibility with regard to the safety rules and procedures of all participants but if a dispute affecting the interpretation or application of safety rules and procedures should arise, the dispute must be resolved in accordance with the procedures specifiedbythesystemoperator.

(5) The Southern African Power Pool operating agreements apply in the case of operational liaison with all international power systems connected to the transmission system.

Operational liaison, permission for synchronisation

174. (1) The system operator must sanction the switching, including shutting down and synchronising, of units and changing over of auxiliaries on all units.

(2) If a participant experiences an emergency, the other participants must assist to an extent as may be necessary to ensure that the emergency does not jeopardise the operation of the networks or plant.

(3) A customer must enter into an operating agreement with the system operator, if it is physically possible to transfer load or embedded generators from one point of supply to another by performing switching operations on the network of the customer.

(4) The operating agreement under subcode (3) must cover at least the operational communication and notice period requirements and switching procedures for load transfers.

Emergency or contingency planning


175. (1) The system operator must develop and maintain contingency plans to manage system contingencies and emergencies that are relevant to the performance of the interconnected power system.

(2) The contingency plans under subcode (1) must -

(a) be developed in consultation with all participants;

(b) be consistent with internationally acceptable utility practices; and

(c) include -

(i) under-frequency load shedding;

(ii) meeting disaster management requirements including the necessary minimum load requirements;

(iii) forced outages at all points of interface; and

(iv) supply restoration.

(3) Emergency plans must allow for quick and orderly recovery from a partial or complete system collapse, with minimum impact on customers.

(4) Emergency plans must comply with Southern African Power Pool agreements and guidelines.

(5) Allcontingencyoremergencyplansmustbeperiodicallyverifiedbyactualteststothe greatest practical extent, as agreed by the parties, without causing undue risk or undue cost.

(6) The costs of the tests referred to in subcode (5) must be borne by the respective asset owners.

(7) The system operator, in consultation with all affected participants, must ensure the coordination of the tests referred to in subcode (5).

(8) The system operator must specify minimum emergency requirements for distributor control centres, power station local control centres and substations to ensure continuous operation of their control, recording, enunciator and communication facilities.

(9) Other participants must comply with the requirements of the system operator for contingency or emergency plans.

(10) Automatic and manual load shedding schemes must be made available under the direction of the system operator.

(11) The system operator must be responsible for determining all operational limits on the transmission system by means of the applicable analytical studies.

(12) Loadflowstudiesmustbeconductedregularlytodeterminetheeffectthatvariouscomponent failures would have on the reliability of the interconnected power system.

(13) Attherequestofthesystemoperator,distributorsmustperformrelatedloadflowstudies on their part of the network and make the results available to the system operator.


System frequency and Area Control Error control under abnormal frequency or imbalance conditions

176. The system operator is responsible for the balancing of supply and demand in real time through the implementation of the energy schedules and utilisation of ancillary services.

Description of normal frequency or balancing conditions

177. (1) The control area is considered to be under normal frequency conditions when -

(a) the immediate demand can be met with the available scheduled resources, including any expensive contingency resources;

(b) the SAPP control performance criteria are not consecutively violated;

(c) the frequency is within the range 49,5 to 50,5 Hz;

(d) the interconnection is intact; and

(e) there are no security and safety issues.

(2) The control area is considered to be under abnormal conditions if it is not in a normal condition as contemplated in subcode (1).

Operation during abnormal conditions

178. (1) When abnormal conditions occur, corrective action must be taken until the abnormal condition is corrected.

(2) The corrective action referred to in subcode (1) includes both supply-side and demand-side options.

(3) Where possible, warnings must be issued by the system operator on expected utilisation of any contingency resources.

(4) The system operator must have a designated person to refer to in periods of abnormal operation, particularly during emergencies.

(5) The order in which emergency resources are to be used may change from time to time.

(6) An updated list must be issued by the system operator.

(7) Termination of the use of emergency resources must occur as the plant shortage situation improves and after frequency has returned to normal.

(8) Automatic under-frequency systems must be kept armed at all times.

Independent action by participants

179. (1) Each participant must have the right to reduce or disconnect a point of connection under emergency conditions if it is necessary for the protection of life or equipment.


(2) If a participant considers it necessary to reduce or disconnect a point of connection as contemplated in subcode (1) the participant must give advance notice of the intended reduction or disconnectionwherepossibleandnofinancialpenaltiesapply.

(3) During emergencies that require load shedding, the request to shed load must be initiated in accordance with agreed procedures.

(4) Following emergency operations necessary to protect the integrity of the interconnected power system or the safety of equipment and human life, the participants must work diligently towards removing the cause of the emergency and the supply must be reconnected immediately after the emergency conditions have passed.

Voltage control

180. (1) The system operator is responsible for the voltage control of the transmission system, at transmission level voltages as well as at the interface between the transmission company and its customers.

(2) Electricity must be supplied at three phase alternating current which must have a nominal voltage between phases and range, at the points of supply, as agreed between the participants.

(3) Transmission system voltages must be controlled during normal operation to be at least within statutory limits at the points of supply.

Fault reporting and analysis or incident investigation

181. (1) Generators must report loss of output and tripping of units and governing to the system operator within 15 minutes of the event occurring.

(2) Distributors and end-use customers must -

(a) report the loss of major loads (>5MVA) to the system operator within 15 minutes of the event occurring; and

(b) give warning of the reconnection of the loads referred to in paragraph (a) with at least 15 minutes advance notice.

(3) Incidents on the interconnected power system involving sabotage or suspected sabotage, as well as threats of sabotage must be reported to the system operator.

(4) Interruptions of supply, disconnections, under or over voltage incidents, quality of supply contraventions or any incident that materially affected the quality of the service to another participant must be formally investigated.

(5) Apreliminaryincidentreportmustbeavailableafterthreeworkingdaysandafinalreport within three months.

(6) The system operator must -

(a) initiate the investigation contemplated in subcode (4);

(b) arrange for the writing of the report; and

(c) involve all affected participants.

(7) The participants referred to in subode (6)(c) must make all relevant required


information available to the system operator.

(8) a major incident must have the following additional requirements:

(a) any participant must have a right to request an independent audit of the report, at theirowncost,iftheyarenotsatisfiedwithit;and

(b) recommendations must be implemented by the participants within the time frames specified.

(9) incidentsmustalsobereportedtotheBoardasdefinedinthelicenceconditions.

(10) system operator is responsible for developing and maintaining an adequate system of fault statistics.

Commissioning

182. (1) The system operator must verify commissioning or maintenance programmes concerning operating at major substations as far as is needed to ensure adequate co-ordination and reliability of the interconnected power system.

(2) All aspects of commissioning, by customers, of new equipment associated with the transmission connection, or re-commissioning of such existing equipment, must be agreed with the system operator in writing before such commissioning starts.

(3) The aspects referred to in subcode (2) include, but are not be limited to the following:

(a) commissioning procedures and programmes;

(b) documents and drawings required;

(c) proof of compliance with standards;

(d) documentary proof of the completion of all required tests;

(e) SCADA information to be available and tested before commissioning; and

(f) site responsibilities and authorities.

(4) A minimum notice period of one month applies from the date of receipt of the request for all commissioning or re-commissioning.

(5) When commissioning equipment at the connection point, the transmission company must liaise with the affected customers on all aspects that could potentially affect the operation of customers.

(6) The transmission company and customers must perform all commissioning tests requiredinordertoconfirmthatthetransmissioncompanyandtheplantandequipmentofcustomersmeets all the requirements of the Transmission Grid Code before going on-line.

(7) Where commissioning is likely to involve a requirement for dispatch or operating for test purposes, the customer must, as soon as possible, notify the system operator of the requirement including reasonable details as to the duration and type of testing required.

Risk of trip

183. (1) Generators must identify and report all tripping risks to the system operator.


(2) Participants must minimise the risk of tripping or loss of output on their own plant and equipment, associated with their operation and maintenance.

(3) Special care must be taken by participants when planning or executing work on protection panels.

(4) The normal outage process set out in code 184 must be followed.

(5) The work referred to in subcode (3) must be treated as risk-related outages by the system operator.

(6) When a risk of trip of equipment or loss of output with an impact exceeding 5MW could occur on any part of the interconnected power system, owing to an operation or maintenance contemplated in subcode (2) and (3), the affected participants must be consulted as to who must accept the risk before work may commence.

(7) The system operator must always be informed of the operations and maintenance contemplated in subcode (2) and must in general coordinate the information and accept the risks.

(8) The affected participants must be informed when the risk has been removed.

PART 2MAINTENANCE COORDINATION OR OUTAGE PLANNING AND TELE-CONTROL

Maintenance coordination or outage planning

184. (1) Optimal reliability of the interconnected power system must be achieved by co-ordinating scheduled outages of generation, the transmission company, distributor, end-use customer, metering, communication and control facilities affecting interconnected power system operation.

(2) The maintenance coordination or outage planning must be done in collaboration with the single buyer.

Roles and responsibilities of outage requester

185. (1) An outage requester must be a formally nominated employee or agent of a distributor, generator, end-use customer or a transmission company.

(2) The responsibilities of an outage requester are to request an outage on plant -

(a) for planned maintenance, repairs, auditing, emergency repairs, construction, refurbishment, inspection, testing; or

(b) to provide safety clearance for other activities such as servitude clearance, line crossings and underpasses.

Roles and responsibilities of transmission company outage scheduler

186. (1) The transmission company outage scheduler must check for multiple requests for an outage of the same network unit.

(2) If the transmission company outage scheduler notices -


(a) another outage request for the same bay, the transmission company outage scheduler must request the parties involved to combine their requests into a single outage; or

(b) conflictingoutages,thetransmissioncompanyoutageschedulermustconsiderthepriorityandrelativeurgencyoftherequestsandreflecttheconsiderationagainstthevalidated request.

(3) The transmission company outage scheduler is responsible for ensuring that negotiations of risk-related outages have taken place.

Roles and responsibilities of system operator outage scheduler

187. (1) The system operator outage scheduler is appointed to assess the viability of ascheduledoutagerequestandtoconfirmorturndowntherequest.

(2) The system operator outage scheduler must optimise plant utilisation by evaluating networkloadcapabilities,differentsystemconfigurationsandriskfactors.

(3) It is also the responsibility of the system operator outage scheduler to co-ordinate and schedule plant that affects international customers.

Outage process

188. (1) The system operator controller on shift at the time of the outage is responsible forfinallysanctioningoralternativelyrefusingtheoutageandensuringthattherelevantoperatinginstructions are issued.

(2) The system operator must develop and maintain an electronic transmission maintenance scheduling system for the coordination of all transmission system outages.

(3) The transmission company must inform all customers of the name and contact details of the respective the transmission company outage schedulers in the different geographic parts of the country.

(4) The system operator must make available to customers an outage schedule of all planned outages on the transmission system.

(5) The outage schedule referred to in subcode (4) must cover a period of one year rollingandmustindicatewhetherthestatusoftheoutageisconfirmedornot.

(6) Whentheneedforanoutageisfirstidentifiedand-

(a) the outage requester has access to the transmission maintenance scheduling system, the outage requester must enter the outage into the transmission maintenance scheduling system referred to in subcode (2) as a requested outage with planned outage dates, times, reason, type of maintenance and request urgency assigned to it; or

(b) the outage requester does not have access to the transmission maintenance scheduling system, the outage requester must contact the relevant transmission company outage scheduler or the system operator outage scheduler to enter the outage as contemplated in paragraph (a).

(7) When the transmission company outage scheduler is satisfied with the request


referred to in subcode (6)(b) and, in the case of a calculated risk, has ensured that negotiation has taken place with the relevant stakeholders the scheduler must mark the outage as a scheduled outage.

(8) When the outage is marked as contemplated in subcode (7), the system operator outageschedulermustconfirmthescheduledoutageifthescheduledoutagesatisfiesallthenecessaryrequirements.

(9) Ifthescheduledoutageisconfirmedascontemplatedinsubcode(8)thetransmissioncompanyoutage schedulermust change the request referred to in subcode (6)(b) to a confirmedbooking in the transmission maintenance scheduling system referred to in subcode (2).

(10) If the confirmedbooking referred to in subcode (9) is subject to theoutcomeofanotherbooking,theconfirmedbookingundersubcode(9)mustreflectthatitislinkedtoanotherbooking.

(11) If the request referred to in subcode (6)(b) cannot be accommodated, it must be marked as refused, with a reason or an alternative suggestion, in the transmission maintenance scheduling system referred to in subcode (2).

(12) Whenitistimefortheconfirmedbookingreferredtoinsubcode(9)tobeexecutedor the outage becomes effective, the status must be changed or taken by the system operator controller who is on shift if sanctioning the outage.

(13) While an outage is in progress the responsible participants may report the actual state of the progress to the system operator controller who is on shift, who must enter the actual state into the transmission maintenance scheduling system referred to in subcode (2) so that the progress of the outage may be monitored by the outage requester and other participants who may be affected by the requested outage.

(14) When the outage is completed and power is restored, the system operator shift controller must change the status of the outage to complete.

(15) When an outage is cancelled it is the responsibility of the person cancelling the outage to furnish the reasons for the cancellation to the system operator.

(16) The system receiving the cancellation contemplated in subcode (15) must enter the cancellation into the transmission maintenance scheduling system referred to in subcode (2) and change the status to cancelled.

(17) Subcodes (15) and (16) also apply to outages that are postponed.

Risk-related outages

189. (1) All risk-related outages must be scheduled a minimum of 14 days in advance with an executable contingency plan in place.

(2) The compilation of the contingency plan referred to in subcode (1) is the responsibility of the relevant transmission company.

(3) The contingency plan referred to in subcode (1) -

(a) is, in some cases, of a permanent nature and in force every time the same system conditions occur; and

(b) may only be prepared once and comes into force again, with minimal changes if needed, when the same outage is scheduled.


(4) Thecontingencyplanreferredtoinsubcode(1)consistsofthefollowingfiveparts:

(a) security linking prior to the outage, to ensure minimal risk to customers;

(b) returning the plant that is on outage back to service as soon as possible;

(c) restoring supply to customers by utilising by-pass schemes;

(d) loadsheddingifnecessaryandloadprofilesmustbemadeavailablebythecustomer;and

(e) list of contact persons.

(5) When a transmission company compiles a contingency plan pursuant to subcode (2) -

(a) the system operator is responsible for identifying risk-related outages;

(b) the system operator and customer control centres are responsible for the security linking contemplated in subcode (4)(a);

(c) the transmission company is responsible for supplying the information relating to returning the plant to service;

(d) the transmission company must develop by-pass schemes with assistance from the system operator and the customer control centre; and

(e) the system operator and customer control centres are responsible for identifying the load at risk and load shedding in the contingency plan.

(6) If the contingency plan referred to in subcode (1) indicates that load shedding must take place, the contingency plan must include -

(a) thetotalamountofloadtobeshedinrelationtotheloadprofile;and

(b) the point at which load of customers must be shed for optimal results.

(7) Thecustomercontrolcentremustconfirmthatitispossibletoexecutethecontingencyplan successfully.

(8) The outage scheduler must contact the control centre a day prior to the outage to ensure that the control centre is in possession and aware of the contingency plan.

(9) Negotiation of all risk-related outages must take place with affected customers a minimum of 14 days prior to the outage being executed unless otherwise agreed.

(10) Where a request for a risk related outage comes from a generator with a requirement for 28 days prior notice of the risk related outage, the time period must be complied with by the parties.

(11) The service provider must involve customers in the planning phase of projects and


outages that will affect them.

(12) Subcodes (1) to (11) apply also to all outages affecting international customers.

(13) The transmission company must give distributors and end-use customers at least 14 days prior notice of planned interruptions.

Maintenance planning between transmission company and generators

190. (1) Each generator must provide the system operator with the following documents in the pro-forma format set out in Annexure 10 to enable the system operator to execute short-term power system reliability inclusive of -

(a) a 52-weeks-ahead outage plan per power station, showing planned outage and return dates and other known generation constraints, updated weekly by 15:00 every Mondayorthefirstworkingdayoftheweek;

(b) anannualmaintenanceoroutageplanperpowerstation,lookingfiveyearsahead,showing planned outage and return dates and other known generation constraints, and issued by 31 December of each year; or

(c) a monthly variance report, explaining the differences between the plan contemplated in paragraph (a) or (b).

(2) Each generator must invite the transmission company to provide inputs into the compiling of the annual maintenance or outage plan referred to in subcode (1)(b), on the basis of ensuring system reliability, and must not unreasonably reject the inputs.

(3) If a generator rejects the inputs contemplated in subcode (2) the generator must substantiate the rejection as reasonable by providing the transmission company with documentary proof of the reasons for the rejection.

(4) Plant versus system risks must be carefully weighed up by the affected participants under all circumstances.

(5) Joint risk assessments must be undertaken and joint contingency plans under these outage conditions must be prepared by the affected participants.

(6) Each generator must ensure the absolute minimum deviation from its annual outage plan and each deviation must be negotiated with the system operator.

(7) The system operator must coordinate network outages affecting unit output with related unit outages to the maximum possible extent.

(8) The objectives to be used by the system operator in this maintenance coordination -

(a) maintaining adequate reserve levels at all times;

(b) ensuring reliability where transmission system constraints exist; and

(c) maintaining acceptable and consistent real-time technical risk levels.

Refusal or cancellation of outages

191. (1) Aparticipantmaynotunreasonablyrefuseorcancelaconfirmedoutage.


(2) Ifaparticipantunreasonablyrefusesorcancelsaconfirmedoutagetheparticipantisliable for the risks associated with that refusal or cancellation.

(3) In the case of the system operator cancelling the request owing to system conditions, the outage requester must bear the cost of such cancellation.

Communication of system conditions, operational information and interconnected power system performance

192. (1) The system operator must -

(a) determine system conditions; and

(b) communicate the system conditions determined under paragraph (a) to all participants.

(2) The system conditions contemplated in subcode (1)(a) are -

(a) based on a steady state and dynamic simulation of the interconnected power system; and

(b) include measures that will enhance reliability.

(3) The system operator must provide participants with operational information as may be agreed from time-to-time and as contemplated in Part 2 of Chapter 6.

(4) The operational information under subcode (3) includes information regarding planned and forced outages on the interconnected power system as determined by the market rules.

(5) The system operator must report on both technical and energy aspects of interconnected power system performance monthly and annually.

(6) The reporting pursuant to subcode (5) includes information on daily demands, energies, losses, interruptions and Codes 229, 230, 231 and 232.

(7) The system operator must, on request by a participant, make available the information contemplated in subcode (6).

Tele-control

193. Where tele-control facilities are shared between participants, operating procedures must be agreed.

CHAPTER 5TRANSMISSION SYSTEM METERING

Principles of transmission metering

194. (1) The following points must have a metering installation -

(a) each point of supply connecting a distributor or end-use customer to the transmission system;

(b) each point of connection between a unit and a distributor or the transmission system; and


(c) each point connecting the networks of Namibia to a neighbouring country.

(2) The type of metering installation at each metering point as contemplated in subcode (1)mustcomplywiththeNRS057:2001meteringspecifications.

(3) Customers with a maximum demand of 5 MVA or more, generators and connections to neighbouring countries must have main and check metering and there must be separate main and check Current Transformer cores but one dedicated Voltage Transformer must be allowed.

(4) A metering point may be located at a point other than the point of connection or the point of supply by mutual agreement between the participants.

(5) Customers may request the installation of their own separate check meters and any extra costs must paid for by the requesting party and the transmission metering administrator must install and control the check meters.

Responsibility for metering installations

195. (1) For the purposes of this Chapter, the transmission company is the transmission metering administrator and owner of the meter.

(2) Thetransmissionsupplybusinessisresponsibleforensuringthatallpointsidentifiedas metering points under code 202 have metering installations.

(3) The transmission metering administrator is responsible for managing and collecting metering information.

(4) Participants connected to or wanting to connect to the transmission system must provide the transmission metering administrator with all information considered necessary to enable the transmission metering administrator to perform metering duties.

(5) In the event of a metering installation being positioned between two distributors -

(a) both distributors are responsible for installing and maintaining the metering installation in accordance with the requirements of this Chapter;

(b) all costs related to the metering installation must be paid for by both distributors; and

(c) the distributors must ensure that the transmission metering administrator is given remote or electronic access to the metering installation where appropriate and if access to the metering installation compromises the security of the installation then metering data must be supplied to the transmission metering administrator on a daily basis in an appropriate format if required.

Metering installation components

196. (1) The following principles apply to all metering installations:

(a) the meter or recorder must be able to store data in memory for 35 days or more;

(b) data stored in either a meter or a recorder must be remotely and locally retrievable;

(c) a meter must be remotely interrogated on a daily basis where possible or as mutually agreed by the affected participants;


(d) a meter must be visible and accessible but access is restricted to authorised staff members only; Data for customers must be historical data situated on a secure server. As and when required, metering impulses must be provided;

(e) a telecommunications medium must be connected to the meter or recorder contemplated in paragraph (a) where possible; and

(f) the meter data retrieval process must be a secure process whereby meters or recorders are directly interrogated to retrieve billing information from their memories.

(g) The accuracy of meters and recorders must be in accordance with the minimum requirementsofNRS057:2001meteringspecifications.

(h) Commissioning of the metering installation and metering data supporting systems must take place in accordance with the requirements of NRS 057:2001 metering specifications.

(i) Both active and reactive energy must be measurable without compromising any requirements of this Chapter.

(j) Themetersmustmeasurebothactiveandreactiveenergyflowinbothdirections.

(k) The meters must be configured to store or record metering data in half-hourlyintegration periods.

(2) If a metering installation is used for purposes other than metering data -

(a) the use must not in any way obstruct metering data collection and accuracy requirements;

(b) the secondary use must be communicated to all participants who may be affected by the secondary use of the installation; and

(c) no secondary user must interfere with Voltage Transformer or Current Transformer circuitry.

(3) Metering installations must be audited in accordance with NRS 057:2001 metering specificationsorequivalent.

Data validation

197. (1) Data validation must be carried out in accordance with NRS 057:2001 meteringspecifications.

(2) In the event of -

(a) electronic access to the meters not being possible;

(b) an emergency bypass or other scheme having no metering system; or

(c) metering data not being available any of the following may be resorted to by the distributor,

the transmission metering administrator may resort to -


(i) manual meter data downloading;

(ii) estimation or substitution subject to mutual agreement between the affected parties;

(iii) profiling;or

(iv) reading of the meter at scheduled intervals.

(3) In the event of an estimation having to be made -

(a) a monthly report must be produced for all estimations made; and

(b) the estimation may not be made on three or more consecutive time slots but if that estimation is made the transmission metering administrator must ensure that the meters are downloaded for the billing cycle.

(4) Not more than 10 slots may be estimated per meter point per month but if that estimation is made the transmission metering administrator must ensure that the meters are downloaded for the billing cycle.

Meter verification

198. InadditiontotheNRS057:2001meteringspecificationsverificationrequirements,meter readings must be compared with the metering data base at least once a year.

Metering database

199. (1) The transmission metering administrator must create, maintain and administer a metering database containing the following information:

(a) nameanduniqueidentifierofthemeteringinstallation;

(b) the date on which the metering installation was commissioned;

(c) the connecting parties at the metering installation;

(d) maintenance history schedules for each metering installation;

(e) telephone numbers used to retrieve information from the metering installation;

(f) type and form of the meter at the metering installation;

(g) fault history of a metering installation; and

(h) commissioning documents for all metering installations.

(2) Informationrelatingtorawandofficialvaluesasindicatedin section 4.2 of the NRS 057:2001meteringspecificationsmustformpartofthemeteringdatabaseandmustberetainedforatleastfiveyearsforaudittrailpurposes.

Testing of metering installations

200. (1) Commissioning, auditing and testing of metering installations must be done inaccordancewiththeNRS057:2001meteringspecifications.


(2) A participant may request the Board that testing of a metering installation be performed and that request may not be unreasonably refused but the costs of the testing must be for the account of -

(a) the requesting participant if the meter is found to be accurate; or

(b) the account of the transmission metering administrator if the meter is found to be inaccurate.

Metering data base inconsistencies

201. In the event of testing revealing that data in the metering database is inconsistent with the data in the meter, the transmission metering administrator must inform all affected participants andmakecorrectionstotheofficialmeteringdata.

Access to metering data

202. (1) Metering data must be accessed through a central database that stores all customer information.

(2) The transmission metering administrator must control access to all metering installations.

(3) Electronic access to the meters may not be granted to the customer or any other party unless special permission has been granted by the Board.

(4) Schedules for accessing metering data from the central database must be administered by the transmission metering administrator in line with section 4.2.3 of the NRS 057:2001 metering specifications.

(5) AllsecurityrequirementsformeteringdatamustbeasspecifiedinNRS057:2001meteringspecifications.

Confidentiality

203. Meteringdataandpasswordsareconfidentialinformation.

CHAPTER 6TRANSMISSION SYSTEM INFORMATION EXCHANGE

PART 1INFORMATION EXCHANGE INTERFACE AND SYSTEM PLANNING INFORMATION

Confidentiality of information

204. (1) Information exchanged between parties governed by this Chapter is confidentialunlessotherwisestatedortheinformationisdefinedasbeinginthepublicdomain.

(2) Confidentialinformationmaynotbetransferredtoathirdpartywithoutthewrittenconsent of the information owner.

(3) Parties must observe the proprietary rights to information of third parties for the purposes of this Chapter.


(4) Parties receiving information must use the information only for the purpose for which it was supplied.

(5) The information owner may request the receiver of information to enter into a confidentiality agreement with the information owner before the information owner providesconfidentialinformation.

(6) AproformaconfidentialityagreementissetoutinAnnexure7.

(7) Parties must -

(a) take all reasonable measures to control unauthorised access to information and to ensure secure information exchange; and

(b) must report any violation of information security to the information owner.

Information exchange interface

205. (1) The parties must identify the following for each type of information exchange:

(a) the names and contact details of the persons designated by the information owner as responsible for the provision of information;

(b) the names and contact details of the parties represented by persons requesting the information; and

(c) the purpose for which the information is required.

(2) Thepartiesmustagreeonappropriateconfirmationproceduresfor thetransferofinformation.

(3) Access to information must be provided by the relevant parties with reasonable motivation and notice.

System planning information

206. (1) Customers must -

(a) provide to the transmission company, without unreasonable delay, information requested by the transmission company on a regular basis for purposes of -

(i) planning and developing the transmission system;

(ii) monitoring current and future power system adequacy and performance; or

(iii) fulfillingstatutoryorregulatoryobligations;and

(b) submit to the transmission company the information listed in Annexure 15 and -

(i) Annexure 8, for distributors or end-use customers; or

(ii) Annexure 9, for generators. (2) The transmission company must keep an updated technical database of the


interconnected power system for purposes of modelling and studying the behaviour of the interconnected power system.

(3) The transmission company must provide customers or potential customers, upon request, with any relevant information that they require to properly plan and design their own networks or installations or comply with their other obligations in terms of the Transmission Grid Code.

(4) The transmission company must make available all the relevant information related to network planning as contemplated in Part 3 of Chapter 3.

(5) Customers must, upon request to upgrade an existing connection or when applying for a new connection, provide the transmission company with information relating to the details specifiedinAnnexure16.

(6) The service-provider may estimate any system planning information not provided by the customer as contemplated in Annexure 8 or 9.

(7) The service-provider must indicate to the customer any data items that have been estimated and the estimated data items are deemed to have been provided by the customer.

(8) Generators must submit to the relevant service-provider all the information set out in Annexure 10 with regard to each generating unit at each power station.

PART 2OPERATIONAL INFORMATION

Pre-commissioning studies

207. (1) Customers must meet all system planning information requirements before the commissioning test date.

(2) The system planning information requirements under subcode (1) include -

(a) confirminganyestimatedvaluesassumedforplanningpurposes;or

(b) where practical, replacing the estimated values contemplated in paragraph (a) with validated actual values and with updated estimates for the future.

(3) The system operator must perform pre-commissioning studies prior to -

(a) sanctioningthefinalconnectionofnewormodifiedplanttothetransmissionsystem;and

(b) using data for exciter, turbine governor, High Voltage Direct Current systems, Flexible Alternating Current Transmission Systems device parameters and settings supplied by customers,

toverifythatallcontrolsystemsarecorrectlytunedandplanningcriteriahavebeensatisfied.

(4) The system operator may request adjustments prior to commissioning should tuning adjustments be found to be necessary by the system operator.

(5) Participants must ensure that exciter, turbine governor, Flexible Alternating Current TransmissionSystemsandHighVoltageDirectCurrentcontrolsystemsettingsareasfinallyrecordedby the system operator prior to commissioning.


Commissioning and notification

208. (1) Participants must give the system operator reasonable advance notice referred to in code 182, of the time at which the commissioning tests will be carried out.

(2) The system operator and the participant must agree on the timeous provision of operational data items set out in Annexure 11.

(3) Participants must jointly verify all measurements and indications for functionality and accuracy once every three years so as to achieve overall accuracy of operational measurements within the limits agreed.

(4) Records of commissioning must be -

(a) maintained for reference by the system operator for the operational life of the plant; and

(b) made available, within a reasonable time, to authorised participants upon request.

(5) A customer connected to the transmission system must ensure that measurement equipment complies with the accuracy classes set out in Annexure 17.

General information acquisition requirements

209. (1) Customers and the transmission company must supply measurements and indications, including the standards set out in Annexure 11, to the system operator.

(2) Where required signals become unavailable or do not comply with applicable standards for reasons within the control of the provider of the information supplied in terms of subcode (1) the provider of the information must report and restore or correct the signals and indications as soon as reasonable.

(3) The measurements and indications contemplated in subcode (1) must be presented to the system operator in a form nominated by the system operator.

(4) The system operator must give notice to a participant if the system operator determines that additional measurements or indications in relation to a plant or equipment of the participant are needed to meet a transmission system requirement.

(5) Thecostsrelatedtoamodificationtothetransmissionsystemarefortheaccountofthe provider of information referred to in subcode (2).

(6) On receipt of the notice contemplated in subcode (4) a participant must promptly ensure that the measurements or indications are made available at the remote terminal unit.

(7) Thedataformatstobeusedandthefieldsofinformationtobesuppliedtothesystemoperator by the various participants are set out in Annexure 11.

Generating unit scheduling

210. The single buyer must provide the data set out in Annexure 12 to the system operator.

Energy market schedules

211. (1) The single buyer must provide the system operator with the daily 24 hours day-ahead energy schedule and the daily price curve before 16:00 Central African Time each day.


(2) After 16:00 Central African Time, the energy schedule referred to in subcode (1) must be made available hourly to ensure the transfer of a new schedule owing to a reschedule by the system operator.

(3) The system operator must import the energy schedule referred to in subcode (1) hourly,atfiveminutestothehour,fordispatch.

Ancillary services market schedules

212. (1) The single buyer must provide the system operator with the daily 24 hours day-ahead ancillary service market schedule before 16:00 Central African Time each day.

(2) After 16:00 Central African Time, the ancillary service market schedule referred to in subcode (1) must be made available hourly to ensure the transfer of a new schedule owing to a reschedule by the system operator.

(3) The system operator must import the ancillary service schedule hourly, at fiveminutes to the hour, for dispatch.

(4) All information exchange requirements for ancillary services that are contracted annually must be included in the contract between the parties.

File transfers

213. (1) Theformatofthefileusedfordatatransferthroughfiletransfersmustbenegotiated with the system operator.

(2) The data must be made available in a common electronically protected directory.

(3) Allfiletransferdatamustbecollectedbythesystemoperatorinlinewiththefileformat set out in Annexure 18.

Inter control centre communication

214. (1) All customer control centres must provide the system operator with network information that is considered reasonable for the security and integrity of the transmission system on request.

(2) The system operator must communicate network information as requested to the customer control centres, as required for safe and reliable operation.

(3) The information exchange between control centres must be electronic and paper-based within the time-frame agreed upon.

Communication facilities requirements

215. The minimum communication facilities for voice and data that are to be installed and maintained between the system operator and participants must -

(a) comply with the applicable International Electro-technical Commission standards for Supervisory Control and Data Acquisition and communications equipment; and

(b) meet the standards set by the system operator in advance of the design of communication facilities..


Information Exchange Tele control

216. (1) The information exchange must support data acquisition from remote terminal units.

(2) The system operator must be able to monitor the state of the interconnected power system via telemetry from the remote terminal unit connected to the plant of a participant.

(3) The signals and indications required by the system operator are set out in Annexure

9, together with other information the system operator may from time to time reasonably require by notice to the participant.

(4) Participantsmust interfacevia the standarddigital interfaces, as specifiedby thesystem operator.

(5) Interface cabinets must be installed in the plant and equipment room of a participant if required by the system operator.

(6) A participant is responsible for providing and maintaining the signalling from the plant and equipment of the participant to the interface cable.

(7) A participant must provide the capability -

(a) for the system operator to deactivate and reactivate the scanning of a given remote terminal unit; and

(b) of monitoring the availability of all remote terminal units centrally.

(8) A participant must comply with the tele control requirements -

(a) applicable to the primary control centre; and

(b) reasonably required for the emergency control centre,

of the system operator.

Telephone or facsimile

217. (1) A customer is responsible for the provision and maintenance of no less than one telephone and one facsimile unit that must be reserved for operational purposes only, and must be continuously attended to and answered without undue delay.

(2) The system operator must use a voice recorder for historical recording of all

operational voice communication with participants.

(3) The voice recordings contemplated in subcode (2) must be available for at least three months.

(4) Thesystemoperatormustmakethevoicerecordsofanidentifiedincidentindisputeavailable within a reasonable time period upon request by a participant or the Board.

Electronic mail


218. (1) Participants must provide the system operator with the electronic mailing address of the contact person and the system operator must provide participants with the mailing address of the contact person of the system operator.

(2) The service-provider must be selected to meet the real-time operational requirements of the system operator.

Access and security of infrastructure at points of supply

219. (1) The system operator must agree with participants on the procedures governing security and access to the Supervisory Control and Data Acquisition (SCADA), computer and communications equipment of the participants.

(2) The procedures under subcode (1) must allow for adequate access to the equipment and information by the system operator for purposes of maintenance, repair, testing and the taking of readings.

(3) A participant must -

(a) designate a person to perform the duties of the information owner in respect of the granting of access to information to third parties; and

(b) disclose the name and contact details of the person designated pursuant to paragraph (a) to the Board.

(4) A participant may, pursuant to subcode (3)(a), designate more than one person.

Time standards for infrastructure at points of supply

220. (1) All information exchange must be global positioning system satellite time signal referenced.

(2) The system operator must ensure broadcasting of the standard time to relevant telecommunications devices in order to maintain time coherence.

Integrity of installation

221. (1) A participant is responsible for optimising the reliability and security of the facilities to comply with the system operator equipment and Original Equipment Manufacturer minimum requirements.

(2) The optimising of reliability and security contemplated in subcode (1) includes the provision, at no charge to the system operator, of an uninterruptible power supply with an eight-hour standby capacity.

Data storage and archiving

222. (1) An information owner must store and archive data.

(2) A party -

(a) must have a system for storing data and information to be used by the party; and

(b) is responsible for own choice, and the costs, of the system contemplated in paragraph


(a).

(3) A system contemplated in subcode 2 must -

(a) be auditable by a party authorised to audit the system;

(b) provide for clear and accessible audit trails on all relevant operational transactions.

(4) All requests that require an audit on a system contemplated in subcode 2 must be undertaken with reasonable notice to the parties.

(5) Theinformationownermustkeepallinformationforaperiodofatleastfiveyearsfromthedatetheinformationwascreated,unlessotherwisespecifiedintheTransmissionGridCode.

(6) The parties must ensure reasonable security against unauthorised access, use and loss of information of the systems that contain the information.

PART 3POST-DISPATCH INFORMATION

Market information

223. (1) The system operator and the transmission metering administrator must provide participants, including the single buyer, with the information contemplated in codes 210, 211 and 212.

(2) Beforethefinalisationoftheinformationreferredtoinsubcode(1)theinformationmust be provided in accordance with codes 224 to 227.

Generation settlement

224. (1) The single buyer must request all data required for settlement of the energy market from the transmission company.

(2) On a request pursuant to subcode (1), the transmission company must make the data available to the single buyer within an agreed time period and acknowledge that the data is confidential.

Ancillary services settlement

225. (1) The single buyer must request all data required for settlement of the ancillary services market from the transmission company.

(2) The transmission company must make this information available, within an agreed timeperiod,withacknowledgementoftheconfidentialityofthedatarequested.

Additional generating unit post-dispatch information

226. The system operator must provide operational information regarding generating unit dispatchandoveralldispatchperformanceasspecifiedinAnnexure13.

Hourly demand metering data

227. The transmission metering administrator must provide participants with hourly metered data pertaining to their installations.


Files used for data transfer

228. (1) Theformatofthefilesusedfordatatransfermustbenegotiatedanddefinedby the supplier and receiver of the information.

(2) Thefiletransfermediamustbenegotiatedanddefinedbybothpartiesinvolved.

(3) Thepartiesmustkeeptheagreednumberoffilesforbackuppurposessoastoenablethe recovery of information in the case of communication failures.

(4) ThefilesthatmaybetriggeredinthetransmissionsystemandthefrequencyoftheoccurrenceoftheeventsthattriggerthefilesaresetoutanddescribedinAnnexure19.

Generator performance data

229. Generatorsmust provide the system operatormonthlywith official performanceindicators in relation to each generating unit at each power station in respect of availability or reliability as detailed in Annexure 14.

Distributor and end-use customer performance

230. (1) The performance measurement of all distributors and end-use customers must be in accordance with the quality-of-supply requirements as contemplated in code 71(2)(b)

(2) Periodic testing of under-frequency load shedding relays must be reported in the format set out in Annexure 20.

System performance information

231. (1) The transmission company must make available monthly the performance indicators for the transmission system, in the format set out in Annexure 21, to the Board, customers and the single buyer.

(2) The transmission company must contract point of supply performance with each customer.

(3) The point of supply performance under subcode (2) includes performance reporting requirements.

System performance information

232. (1) The following interconnected power system operational information must be made available by system operator -

(a) daily:

(i) the hourly actual demands of the previous day (MW); and

(ii) the reserve amounts over the morning and evening peaks of the previous day


(MW); and

(b) annually:

(i) the annual peak (MW), date and hour; and

(ii) the annual minimum MW, date and hour.

CHAPTER 7TRANSMISSION SYSTEM RENEWABLE ENERGY TECHNOLOGIES

Frequency response

233. (1) During network frequency deviations a connected renewable energy plant or PV plant must have the following frequency response settings as depicted in Annexure 22:

(a) a dead band setting or constant power versus frequency response in a band settable around the nominal frequency of 50Hz with a resolution of 0.05Hz (49Hz <= f1 < 50Hz < f2 <= 51Hz);

(b) an upper band frequency setting where f2<f<f3<52.5Hz the power is ramped down at a settable rate to a % of active power order in accordance with a droop setting of k2=dP/df<0;

(c) power is ramped down to 0 for f>f3<52.5Hz with the option to disconnect from the grid;

(d) if the over-frequency does not exceed f3 and power has been ramped down, and

the frequency decreases again towards the upper dead band frequency f2, it is only ramped up again to a percentage of the power before the disturbance.

(e) the power after disturbance (Pad) is equal to the power before the disturbance (Pbd) which is normally also equal to the maximum available power times a factor k3, thus k3= Pad/Pbd<1;

(f) a lower band frequency setting where 48Hz<f0<f<f1 power is ramped up to a %

of max available power at that time, if more power is available than before the disturbance or if an inherent overload capability exists, in accordance with a droop setting of k1=dP/df<0;

(g) for frequencies below f0, power remains constant with the option to disconnect from

the grid for frequencies lower than 48Hz;

(h) once power is ramped up for f0<f<f1, it can be ramped down again when f1<f<f2 automatically to normal power setting as it was set during pre-transient operation; or

(i) after a disturbance where the k3 factor has come into play, a reset command should be available to restore the power order to the maximum available power order with an optional automatic reset after settable time duration.

Voltage operating and regulation requirements

234. (1) A connected renewable energy plant must be able to -

(a) operate continuously at a voltage range of 0.9pu – 1.1pu at frequencies of 49Hz to 51Hz for -


(i) conditions outside the transient response required for low voltage ride-through set out in code 235; and

(ii) the transient frequency response required in code 233;

(b) trip after 2 seconds of steady-state over- and under voltage;

(c) trip after 3 seconds of steady-state over or under frequency; and

(d) regulate the voltage within its reactive power capabilities at a voltage set point settable between 0.9pu and 1.1pu voltage and the voltage set point should be settable with a resolution of 0.01pu or smaller.

(2) A steady-state voltage ramp rate must be settable in a range of 1kV/min to 100kV/min.

(3) Transient voltage control loop gain settings should be adjustable as recommended by dynamic studies performed for each project or network location of the plant.

(4) Switching in or out of feeders or equipment inside the plant must not cause a transient voltage change of more than 0.02pu voltage at the point of common coupling for normal fault level conditions,andnotmorethan0.05puunderpre-definednetworkcontingenciesorminimumfaultlevel.

(5) Transient overvoltage conditions to be catered for are to be in accordance with relevant IEC equipment standards.

Low voltage ride-through requirements

235. (1) During a voltage dip, a connected renewable energy plant must have the low voltage ride-through ability to -

(a) stay connected to the network; and

(b) give full available capacitive reactive power support for events where the voltage of the lowest phase is -

(i) 0 pu< U < 1 pu for t <= 0.2s;

(ii) U>0.47222t-0.09444 pu for 0.2 < t <= 2s; or

(iii) U>0.85 for 2 < t <= 120s.

(2) For transient voltages, with the plant availing maximum reactive power or as required, below the nominal voltages and with longer durations than given in subcode (1)(b), the renewable energy plant may disconnect and reconnect to the network within 1 second after the voltage has recovered to >0.9pu of nominal voltage.

(3) An illustrativeclarificationof lowvoltage ride-throughresponsecontemplated insubcodes (1) and (2) is set out in Annexure 23.

Reactive power control

236. (1) A renewable energy plant must not require any reactive power to start up if the voltage is within the 0.9pu to 1.1pu range.


(2) Both power factor control and voltage control with voltage set point capability as specifiedincode234mustbeavailableforallplants.

(3) Power factor must be settable at 0.9 lagging to 0.9 leading in power factor control mode at maximum rated power, and reactive power equal to the power factor control mode reactive power capability at maximum power must be available for voltage support in voltage control mode at any power order as shown in the PQ Capability Chart in Annexure 24.

(4) Constant Q control mode is deemed optional.

(5) Where Q control is provided, the steady-state ramp rate (MVAR/min) and resolution shouldbesimilartoequatetothevoltageregulationrequirementsforthespecificnetworklowestfault level case.

Active power control

237. (1) Any connected renewable energy plant must be able to reduce active power below the immediate available power level of a plant.

(2) Any change of active power level must be governed by a power ramp rate (MW/min) agreed between the generation plant and the transmission company or system operator and be settable between 1% of plant power rating/min and 50MW/min.

(3) The ramp rate must be settable for different operations such as start-up, shut-down, and normal power order changes.

(4) Theactivepowermustnotbeinfluencedbythevoltageatpointofcommoncouplinggiven that it is within the range as set out in code 234.

Harmonic distortion requirements

238. (1) Total voltage harmonic distortion and individual voltage harmonics caused by the connected renewable energy plant must not exceed the levels given in Annexure 25, but the system operator may limit the total voltage harmonic distortion and individual voltage harmonics below the levels given in that Annexure.

(2) Current harmonics may not be specified for generating plant except where thetransmission company or system operator can motivate certain limitations for exceptional cases due to possible normal-based or contingency-based harmonic resonance conditions or harmonic cross-modulation with other network devices.

(3) The IEEE-519-1992 standard may serve as a general guideline to harmonic distortion requirements.

Unbalance requirements

239. The fundamental negative phase sequence voltage component generated by the connected renewable energy plant must not exceed 2% compared to the fundamental positive phase sequence voltage component.

General protection and control requirements

240. The following protection and control functionality must be available for each renewable energy plant interface with the transmission or distribution grid:


(a) islanding detection and settable response for island frequency control or shutdown;

(b) dead network start-up blocking;

(c) synchronising facilities with network;

(d) configurableinter-tripandrunbacksignals;

(e) protectionfunctionssuchasdefinite-andinversedefiniteminimumtime(IDMT)over-current, earth fault detection, differential protection, overvoltage detection, as agreed between the parties;

(f) unitised protection for transformers, cables, and busbars;

(g) where protection or control signals are exchanged, interface point details including -

(i) wetting voltage;

(ii) junction box terminal layout;

(iii) cablenumberingorfibreopticpatchpanel,

will be as agreed between the parties;

(h) other requirements that the transmission company or network operator considers necessary; and

(i) metering requirements are as set out in Chapter 5.

General telecommunication and Supervisory Control and Data Acquisition (SCADA) requirements

241. (1) Telecommunications interface between the plant and the transmission company network via fibre optic or power line carriermust be available as agreed between thetransmission company and the renewable energy plant.

(2) Supervisory Control and Data Acquisition protocol capability to the national control centre is available either via IEC60870-5-101, IEC60870-5-104 or IEC61850.

(3) The Supervisory Control and Data Acquisition signals to be made available, by the renewable energy plant, for network operations, to the national control centre are -

(a) relevant indications such as breakers, disconnectors, and earth links;

(b) alarm indications including plant protection alarms or auxiliary alarms;

(c) analogue values including active power, available active power, reactive power, voltage, current, frequency, tap changer positions, active set points, wind information or solar information;

(d) control of analogue set points including active power set point, voltage set point or power factor set point; and

(e) control commands including start, stop or reset of maximum available power after


disturbance, relevant breaker open or close must be available as agreed.

(4) Supervisory Control and Data Acquisition protocol address lists, update rates or dead-bands for analogue and digital indications must be agreed during project execution.

Power system studies and models

242. (1) A renewable energy plant dynamic model must be -

(a) made available by the renewable energy plant to the transmission company, in the form of at least two software packages agreed on by the renewable energy and the transmission company, for network dynamic studies and protection studies; and

(b) structured to -

(i) be a detailed, topology, model describing the structure of the wind power plant.

(ii) be an aggregated model of the wind power plant, that describes the plant by means of one equivalent wind turbine generator and renewable energy plant component or a few equivalent wind turbine generator components and renewable energy plant components; and

(iii) enable at least themodification of the parameters of voltage control andreactivepowercontrol functions relating to the specificationsofnetworkparameters.

(2) The functionalities relating to active and reactive power control must be executable freelyduringasimulationrunbymeansofamodifiableinterfaceforpowercontrol.

(3) Renewableenergyelectromagnetictransientmodelsorharmonicloadflowmodelsmust be made available to the transmission company, in the form of at least two software packages agreed on by the renewable energy plant and the transmission company, for harmonic integration studies.

(4) If electromagnetic transient models referred to in subcode (3) are not available, harmonic current generation may be given as a percentage of fundamental current with phase rotationsandrelativeanglesspecified.

(5) Reduced network models of the transmission or distribution network can be provided to a renewable energy plant manufacturer or photovoltaic plant manufacturer for internal protection studies or harmonic studies.

Energised system testing

243. (1) In order to verify the performance of a renewable energy plant energised system testing and measurements must be conducted in conjunction with the transmission company as agreed by the renewable energy plant and the transmission company.

(2) The energised system testing referred to in subcode (1) may include -

(a) auditingofmeteringsystemsandverificationofplantmaximumpoweroutput;

(b) control mode selection changes including V-control, PF-control or Q-control and step response tests as agreed by the parties;


(c) power order set point tests, power ramp tests, voltage set point tests or voltage ramp tests, as agreed by the parties;

(d) verificationofPQcapabilitycurveas far asnetworkconfigurationallowswithinallowable voltages;

(e) island detection test;

(f) staged single phase fault on transmission company side of point of common coupling to test low voltage ride-through response with transient recordings as agreed;

(g) harmonic voltage and current measurements at the point of common coupling for different power levels as agreed by the parties and during a one week continuous operationwithdifferentsystemconfigurations;

(h) other tests as agreed by the parties; or

(i) plant-side information and data recorded by dynamic system monitors, wind or solar measurements, harmonic content or voltage dip monitoring made available as contemplated in subcode (3).

(3) Plant-side information and data recorded by dynamic system monitors, wind or solar measurements, harmonic content or voltage dip monitoring must be made available during and after energised system testing referred to in subcode (1) to compare with the transmission company sidemeasurementsforthepurposesofperformanceverification,controlsystemtuningandplanninginformation.

(4) On-line access to plant-side information with required security measures would be an advantage.


ANNEXURE 1

TRANSMISSION GRID CODE AMENDMENT OR EXEMPTION APPROVAL PROCESS


ANNEXURE 2

CONTRACTING FRAMEWORK FOR PARTICIPANTS


ANNEXURE 3

GENERATOR CONNECTION CONDITIONS

Table 1: Summary of the requirements applicable to specific classes of units

Grid Code Requirement Units other than Hydro (MVA rat-ing)

<20 20 to 100 100 to 200

200 to 300 300 - 800 >800

GCR1 Plant availability -Depends on

System Requirements

Yes Yes Yes Yes

GCR2 Plant reliability -Depends on

System Requirements

Yes Yes Yes Yes

GCR3 Protection - Backup Imped-ance Yes Yes Yes Yes Yes Yes

- Loss of Field -Depends on

System Requirements

Yes Yes Yes Yes

- Pole Slipping -Depends on

System Requirements

Depends on Sys-

tem Require-

ments

Yes Yes Yes

- Trip to House Load - -

Depends on Sys-

tem Require-

ments

Depends on Sys-

tem Require-

ments

Yes Yes

- Gen TRANS-FORMER backup earth fault

Yes Yes Yes Yes Yes Yes

- HV Breaker Fail Yes Yes Yes Yes Yes Yes - HV Breaker Pole Disagreement Yes Yes Yes Yes Yes Yes

- Unit Switch-onto-standstill Protection

Depends on System

RequirementsYes Yes Yes Yes

- Main Protection only Yes Yes

Depends on Sys-

tem Require-

ments

- - -

- Main Protection (monitored) or main and backup

- -

Depends on Sys-

tem Require-

ments

- -

- Main and Backup Protection (both monitored)

- - -

Depends on

System Require-

ments

Yes


GCR4 Ability To Island - -

Depends on

System Require-

ments

Yes Yes Yes

GCR5 Excitation system requirements Yes Yes Yes Yes Yes Yes

- Power System Stabilizer - -

Depends on

System Require-

ments

Depends on

System Require-

ments

Yes Yes

- Limiters -Depends on

System Requirements

Yes Yes Yes Yes

GCR6 Reactive Capabili-ties

Depends on Sys-

tem Require-

ments

Depends on System


GCR7 Multiple Unit trip-ping -

Depends on System

Requirements

If the total station output is greater than the single largest contin-

gencyasdefinedforinstantaneousreserve

If more than

1 unit at station

GCR8 Governing

Depends on Sys-

tem Require-

ments

Yes Yes Yes Yes Yes

GCR9 Restart after Station Blackout -

Depends on System

Requirements



If more than

1 unit at station

GCR10 Black Starting - If agreed If agreed If agreed If agreed If agreed

GCR11External Supply Disturbance With-stand Capacity

Depends on Sys-

tem Require-

ments

If more than 5 unit at sta-

tion



If more than

1 unit at station

GCR12

On load tap Chang-er for generating Unit step up transform-ers

Depends on Sys-

tem Require-

ments

Yes Yes Yes Yes Yes

GRC13 Emergency unit capabilities

Depends on Sys-

tem Require-

ments

Depends on System


GCR14Independent action for control in sys-tem island

- -

Depends on Sys-

tem Require-

ments

Yes Yes Yes


Table 2: Summary of the requirements applicable to specific classes of unitsGrid Code Requirement Hydro Units (MVA rating)

<20 20 to 100 100 to 200 200 to 300

300 - 800 >800

GCR1 Plant availability -Depends on

System Requirements

Yes Yes Yes Yes

GCR2 Plant reliability -Depends on

System Requirements

Yes Yes Yes Yes

GCR3 Protection - Backup Imped-ance Yes Yes Yes Yes Yes Yes

- Loss of Field -Depends on

System Requirements

Yes Yes Yes Yes

- Pole Slipping -Depends on

System Requirements

Depends on System

Require-ments

Yes Yes Yes

- Trip to House Load - -

Depends on System

Require-ments

Depends on System Require-

ments

Yes Yes

- Gen TRANS-FORMER backup earth fault

Yes Yes Yes Yes Yes Yes

- HV Breaker Fail Yes Yes Yes Yes Yes Yes - HV Breaker Pole Disagreement Yes Yes Yes Yes Yes Yes

- Unit Switch-onto-standstill Protection

Depends on System


- Main Protection only Yes Yes

Depends on System

Require-ments

- - -

- Main Protection (monitored) or main and backup

- -


ments

- -

- Main and Backup Protection (both monitored)

- - -

De-pends

on System

Re-quire-ments

Yes

GCR4 Ability To Island - - - - - -

GCR5 Excitation system requirements Yes Yes Yes Yes Yes Yes

- Power System Stabilizer - -

Depends on System Re-quirements

Depends on

System Require-

ments

Yes Yes


- Limiters -Depends on

System Requirements

Yes Yes Yes Yes

GCR6 Reactive Capabili-ties

Depends on Sys-

tem Require-

ments

Depends on System


GCR7 Multiple Unit trip-ping -

Depends on System

Requirements

If the total station output is greater than the single largest contingency asdefinedforinstantaneousreserve

If more than

1 unit at sta-tion

GCR8 Governing

Depends on Sys-

tem Require-

ments

Yes Yes Yes Yes Yes

GCR9 Restart after Station Blackout -

Depends on System

Requirements


If more than

1 unit at sta-tion

GCR10 Black Starting - If agreed If agreed If agreed If agreed If agreed

GCR11External Supply Disturbance With-stand Capacity

Depends on Sys-

tem Require-

ments

If more than 5 unit at station


If more than

1 unit at sta-tion

GCR12

On load tap Chang-er for generating Unit step up transform-ers

Depends on Sys-

tem Require-

ments

Yes Yes Yes Yes Yes

GRC13 Emergency unit capabilities

Depends on Sys-

tem Require-

ments

Depends on System


GCR14Independent action for control in sys-tem island

- -


ments

Yes Yes Yes

Table 3: Standard Voltage LevelsUn(kV)

Um(kV)

(Um-Un)/Un%

765 800 4,58400 420 5,00330 346.5 5,00275 300 9,09220 245 11,36132 145 9,8588 100 13,63


66 72,5 9,8544 48 9,0933 36 9,0922 24 9,0911 12 9,09Table 4: Target Voltages for Planning PurposesMinimum steady state voltage on any bus not supplying a customerWith multiple feeder supplies:With single feeder supplies and after contingency for multiple feeder supplies:

0.95 Un

0.90 UnMaximum harmonic voltage caused by customer at PCC: According to NRS

048Maximum negative sequence voltage caused by customer at PCC: According to NRS

048Maximum voltage change due to load varying N times per hour: (4.5 log10n)% of

UnMaximum voltage decrease for a 5% load increase at receiving end of system (without adjustment):

0.05 Un


ANNEXURE 4

SURVEYING, MONITORING AND TESTING FOR GENERATORS

1. Introduction

Thissectionspecifiestheprocedurestobefollowedincarryingoutthesurveying,monitoringortestingoftoconfirmthe-

(a) compliance by power stations with the Transmission Grid Code

(b) provision by power stations of ancillary services which they are required or have agreed to provide.

2. Scope

This Annexure applies to generators.

3. Request for surveying, monitoring or testing

The system operator may at any time, although it may not do so more than twice in any calendar year in respect of any particular power station except to the extent that it can on reasonable grounds justify the necessity for further tests or unless the further test is a re-test, issue an instruction requiring a power station to carry out a test, at a time no sooner than 48 hours from the time that the instruction was issued, to demonstrate that the relevant power station complies with the Transmission Grid Code.

4. Ongoing monitoring of performance of unit

(1) A generator must monitor each of its units during normal service to confirm ongoingcompliance with the applicable parts of Chapter 3.

(2) If a generator detects a deviation in its unit the generator must report the deviation to the systemoperatorwithinfiveworkingdays.

(3) A generator must keep records -

(a) relating to the compliance by each of its units with each code of Chapter 3 applicable to that unit; and

(b) setting out the information that the system operator or transmission company reasonably requires for assessing power system performance including actual unit performance during abnormal conditions.

(4) Within one month after the end of June and December, a generator must provide the system operator with a report detailing the compliance by each unit of the generator with every applicable code of Chapter 3 during the past six month period.

(5) The template for purposes of subitem (4) is set out in Annexure 8.

5. Procedures

(1) Unit protection system grid code requirement GCR 3


Parameter ReferenceProtection func-tion and setting integrity study

APPLICABILITY AND FREQUENCYPrototype study: All new power stations coming on line or power stations where major refurbishment or upgrades of protection systems have taken place.

Routine review: Allpowerstationseveryfivetosixyears.

PURPOSE

To ensure that the relevant protection functions in the power station is co-ordinated and aligned with the system requirements. PROCEDURE

Prototype:1. Establish the system protection function and associated trip level

requirements from the transmission company.2. Derive protection functions and settings that match the power

station plant, the transmission company plant and system requirements.

3. Confirmthestabilityofeachprotectionfunctionforallrelevantsystem conditions.

4. Document the details of the trip levels, stability calculations for each Protection function.

5. Convert protection tripping levels for each protection function into per unit base.

6. Consolidate all settings in per unit base for all protection functions in one document

7. Derive actual relay dial setting details and document the relay setting sheet for all protection functions.

8. Document the position of each protection function on one single line diagram of the generating unit and associated connections.

9. Document the tripping functions for each tripping function on one tripping logic diagram.

10. Consolidate detail setting calculations, per unit setting sheets, relay setting sheets, plant base information the settings are based on, tripping logic diagram, protection function single line diagram and relevant protection relay manufacturers information into one document.

11. Submit to the transmission company for their acceptance and update.

12. Provide the transmission company with one original reference copy and one working copy.

Review: 1. Review prototype 1 to 10 above.2. Submit to the transmission company for their acceptance and

update.3. Provide the transmission company with one original reference

copy and one working copy.

ACCEPTANCE CRITERIA

All protection functions are set to meet the necessary protection requirements of the transmission system and power station plant with minimal margin. Optimal fault clearing times and maximum plant availability.

Submit a report to the transmission company one month after commissioningforprototypestudyorfivetosixyearsforroutinetests.


Parameter ReferenceProtection integrity tests

APPLICABILITY

Prototype test: All new power stations coming on line and all otherpowerstationsaftermajormodificationsorrefurbishmentofprotection or related plant.

Routine test of all power stations:fivetosixyearsoraftermajoroverhaul of plant.

PURPOSE

Toconfirmthattheprotectionhasbeenwiredandfunctionaccordingtothespecified.

PROCEDURE

1. Applyfinalsettingsasperagreeddocumentationtoallprotectionfunctions.

2. With the generator unit off load and de-energized, inject appropriatesignalsintoeveryprotectionfunctionandconfirmcorrect operation and correct calibration. Document all protection function operations.

3. Carry out trip testing of all protection functions, from origin (e.g. Buchholz relay) to all tripping output devices (e.g. HV Breaker). Document all trip test responses.

4. Apply short circuits at all relevant protection zones and with generator at nominal speed excite generator slowly, record currentsatallrelevantprotectionfunctions,andconfirmcorrectoperation of all relevant Protection functions. Document all readings and responses. Remove all short circuits.

5. With the generator at nominal speed, excite generator slowly recordingvoltagesonallrelevantProtectionfunctions.Confirmcorrect operation and correct calibration of all protection functions. Document all readings and responses.

ACCEPTANCE CRITERIA

All Protection functions fully operational and operate to required levels within the relay original equipment manufacturer (OEM) allowable tolerances.

Measuringinstrumentationusedmustbesufficientlyaccurateandcalibrated to traceable standard.Submit a report to the transmission company one month after test.


(2) Unit islanding capability grid code requirement GCR 4

Parameter Reference

IslandingAPPLICABILITY

Prototype test: For all other fossil and nuclear power stations

Routine test: For stations that have contracted to island under the ancillaryservicesagreement.5-6yearlyoraftermodificationsdoneto plant that may effect islanding capability

Continuous monitoring: Where in the day to day running of the plant, a real condition arises where a generating unit is required to island, and the Islanding takes place successfully, and the islanding conditionissustainedasspecifiedunderacceptancecriteriabeloworis called to synchronize and complete synchronizing successfully it must be considered as a successful islanding test.

PURPOSE

Toconfirmthatageneratingunitsthathavespecifiedand/orcontractedto provide an islanding service, complies. Islanding is the ability of a generating unit to suddenly disconnect from the transmission system by the opening the HV breaker, and automatically control all thenecessarycriticalparameterssufficientlytomaintaintheturbine-generator at speed and excited and supplying its own auxiliary load. This islanded mode must be sustained for at least 20 minutes without tripping of the turbine, boiler, excitation system, or other systems critical to sustain an islanding condition.

PROCEDURE

• Generating unit running at steady state conditions above 60%full load conditions.

• All protection and control systems in normal operatingconditions.

• Nospecialmodificationstotheplantforthepurposeofthetest,accept installation of monitoring equipment, is allowed.

• Theunitsuppliesallitsownauxiliaryloadduringthetest• No operating is allowed for the first 5minutes following the

initiation of the islanding.• Equipmentisconnectedtothegeneratingunitthatrecordscritical

parameters. The following minimum parameters is recorded:(a) turbine speed;(b) alternator load;(c) alternator voltage and current;(d) exciter voltage and current;(e) unit board voltage;(f) anticipatory device position, where installed; and(g) system frequency.

• InitiationoftheislandingisdonebyopeningtheHVBreaker.

ACCEPTANCE CRITERIA

The turbine must settle at or close to its nominal speed, the excitation system must remain in automatic channel, supplying all the auxiliary load of the unit. The islanding condition must be sustained for at least 20 minutes.

.


(3) Excitation system grid code requirement GCR 5

Parameter ReferenceExcitation and setting integrity study

APPLICABILITY AND FREQUENCY

Prototype study: All new power stations coming on line or power stations where major refurbishment or upgrade of protection systems have taken place.

Routine review: Allpowerstationseveryfivetosixyears.

PURPOSE

To ensure that the excitation systems in the power station is co-ordinated and aligned with the system requirements. PROCEDURE

Prototype:1. Establish the system excitation system performance requirements

from the transmission company.2. Derive a suitable model for the excitation system according to

IEEE421.5 or IEC 60034.16.2. Where necessary, non-standard models (non IEC or IEEE) must be created.. This may require frequency response and bode plot tests on the excitation system as described in IEEE 421.2.1990.

3. Submit the model to the transmission company for their acceptance.

4. Derive excitation system settings that match the power station plant, transmission system plant and system requirements. This includes the settings of all parts of the excitation system such as the chop-over limits and levels, limiters, Protection devices, alarms.

5. Confirm the stability of the excitation system for relevantexcitation system operating conditions system conditions.

6. Document the details of the trip levels, stability calculations for each setting and function.

7. Convert settings for each function into per unit base and produce a high level dynamic performance model with actual settings in P.U. values.

8. Derive actual card setting details and document the relay setting sheet for all setting functions.

9. Produce a single line diagram or block diagram of all the functions in the excitation system and indicate signal source.

10. Document the tripping functions for each tripping on one tripping logic diagram.

11. Consolidate detail setting calculations, model, per unit setting sheets, relay setting sheets, plant base Information the settings are based on, tripping logic diagram, protection function single line diagram and relevant protection relay manufacturers Information into one document.

12. Submit to the transmission company for their acceptance and update.

13. Provide the transmission company with one original master copy and one working copy.

Review: Review prototype 1 to 10 above.


Submit to the transmission company for their acceptance and update.Provide the transmission company with one original master copy and one working copy update if applicable.

ACCEPTANCE CRITERIA

Excitation system is set to meet the necessary control requirements in an optimized manner for the performance of the transmission system and power station plant. Excitation system operates stable both internally and on the network.

Submit a report to the transmission company one month after commissioning for prototype study or five to six years for routinetests, within one month after due date expiry.

Excitation response tests APPLICABILITY

Prototype test: All new power stations coming on line and all other power stations aftermajormodificationsor refurbishment ofprotection or related plant.

Routine test: All power stations 5 to 6 years or after major overhaul of plant.

Prototype test: All new power stations coming on line and all otherPowerStationsaftermajormodificationsor refurbishmentofProtection or related plant.

Routine test: All power stations 5 to 6 years or after major overhaul of plant.

PURPOSE

Toconfirmthat theexcitationsystemperformsasper thespecifiedacceptance criteria below.

PROCEDURE

With the generator off line, carry out frequency scan or bode plot tests on all circuits in the excitation system critical to the performance of the excitation system.

With the generator in the open circuit mode, carry out the large signal performance testing as described in IEEE 421.2 of 1990. With the generator connected to the network and loaded, determine time response, ceiling voltage and voltage response and carry out the small signal performance tests according to IEE 421.2.1990. Also carry out power system stabiliser tests and determine damping with and without power system stabiliser.

Document all responses.

ACCEPTANCE CRITERIA

Excitation system meets the necessary control requirements in an optimised manner for the performance of the transmission system and power station plant as specified. Excitation system operatesstable both internally and on the network. Power system stabilisers set for optimised damping.


(4) Unit Reactive Power Capability Grid Code Requirement GCR 6

Parameter Reference

Reactive power capability

APPLICABILITY


PURPOSE

Toconfirmthatthereactivepowercapabilityspecifiedaremet.

PROCEDURE

The duration of the test will be for a period of up to 60 minutes during which period the system voltage at the grid entry point for the relevant generating unit will be maintained by the generator at the voltagespecifiedbyadjustmentofreactivepowerontheremaininggenerating units, if necessary.

ACCEPTANCE CRITERIA

Generating unit will pass the test if it is within ±5% of the capability registered with the transmission company

Submit a report to the transmission company one month after test.

(5) Power station multiple unit trip grid code requirement GCR 7

Parameter ReferenceMultiple unit tripping (MUT) tests, study and survey

APPLICABILITY

Prototype tests, study or survey:• Newpowerstationscomingonline,items1to5belowor• Power stations where major modifications or changes have

been implemented on plant critical to multiple unit tripping. Applicable criteria 1 to 5 below.

Routine assessment: All power stations. Criterion 5 below. Annually

Routine testing:Allpowerstations.Everyfivetosixyearsorafteramajor overhaul. Criteria 1 to 4 below.

PURPOSE

ToconfirmthatapowerstationisnotsubjectedtounreasonableriskofMUTasdefinedinconnectioncodesection2.2.1.5.

PROCEDURE AND ACCEPTANCE CRITERIA

1. Emergency supply isolation test: On all emergency supplies (e.g. DC supplies) common to more than one generating unit, isolate supply for at least one second, with the unit running at full load under normal operating conditions. Tests are carried out on one unit at the time. Where two supplies feed one common load, isolation of one supply at a time would besufficient. Confirmthat theunitorpartof theunitplantdoes not trip. No change in the unit output must take place. Document results.


2. Disturbance on DC supply survey: On all DC supplies common to more than one generating unit, carry out a survey of the immunity of all devices that are part of tripping circuits, to supply voltage according to appropriate IEC standard. All devices on DC supplies common to more than one unit that form part of tripping circuits or that can cause tripping or Load Reduction on a unit must comply to the appropriate IEC standard.Documentfindings.

3. Uninterruptible power supplies (UPS) integrity testing: On all UPS’s supplying critical loads that can cause tripping of morethanonegeneratingunitwithinthetimezonesspecifiedin 2.2.1.5, isolate the AC supply to the UPS for a period of at least 1 minute. Where two UPS’s supply one common load, one UPS at a time can be isolated. Load equipment must resume normal operation. Document results.

4. Earth mat integrity inspection and testing: Carry out an inspection and tests on all parts of the power station earth mat that is exposed to lighting surge entry and in close proximity to circuits vulnerable to damage that will result in tripping of morethanonegeneratingunitwithinthetimezonesspecifiedin 2.2.1.5 (e.g. Chimney on fossil power stations or penstock on hydro power stations) Confirm that all the earthing andbonding is in place, and measure resistances to earth at bondingpoints..Documentfindingsandresults.

5. MUT risk assessment: Identify all power supplies, air supplies, water supplies, and other supplies or systems common to more than one generating unit than is likely to cause the tripping of more than one generating unit within the MUTtimezones specified in section2.2.1.5. Calculate theprobability of all the Zone 1, Zone 2 and Zone 3 MUT risk areasforthepowerstation.Documentallfindingslistingallrisks and probabilities.

No unreasonable MUT items as listed in 2.2.1.5 must be present. Report to be submitted to the transmission company one month after testing. Routine studies, and survey reports to be submitted one month after expiry of due date.

(6) Governing system grid code requirements GCR 8

Parameter Grid Code Reference

Governing response tests

APPLICABILITY


Routine test: All units to be monitored continuously, additional tests may be requested by the system operator.

PURPOSE

Prove the unit is capable of the minimum requirements required for governing.


PROCEDURE

1. Frequency or speed deviation to be injected on the unit for 10 minutes.

2. Real power output of the unit is to be measured and recorded.

ACCEPTANCE CRITERIA

Minimum requirements set out in codes 43 to 53 are met.

(7) Unit restart after station blackout capability grid code requirement GCR 9

Parameter ReferenceRestart after station blackoutSurvey

APPLICABILITY

Prototype survey: Procedure 1 for new power stations or power stationswheremodificationshavebeencarriedoutonplantcriticaltomultiple unit restarting.

Routine survey: All power stations. Procedure 2 every three months.

PURPOSE

Toconfirmthatapowerstationcanrestartunitsimultaneouslytothecriteria outlined in section 2.2.1.7 after a station blackout condition.

PROCEDURE

1. Plant capacity survey:• Identifyallsupplysystemscommontotwoormoresystems(e.g.

power supplies, crude oil, air, demin water)• Determinethequantityandsupplyraterequiredtosimultaneously

restartthenumberofunitsspecifiedinsection2.2.1.7• Document listofcriticalsystems, requiredstock,studydetails

andfindings.

2. Survey of available stock:• Foreachoftheapplicablecriticalsystemsidentified,document

the average stock for the year, minimum stock and duration below critical stock levels.

ACCEPTANCE CRITERIA

More than 95% of the time of the year, all stocks above critical levels.

Report to be submitted to the transmission company one month after commissioning. Routine survey reports to be submitted one month after expiry of due date.


(8) Power station black start capability grid code requirement GCR 10

Parameter Reference

Unit black starting APPLICABILITY

Routine Test: Power stations that have contracted under the ancillary services to supply unit black start services. When called for by the transmission company but not more than once every two years

PURPOSE

Demonstrate that a black start unit has a black start capability.

PROCEDURE

• Therelevantgeneratingunitmustbesynchronisedandloaded;• Alltheauxiliarygasturbinesandauxiliarydieselenginesinthe

black start station in which that generating unit is situated, must be shutdown.

• Thegeneratingunitmustbede-loadedandde-synchronisedandall alternating current electrical supplies to its auxiliaries must be disconnected.

• Theauxiliarygasturbine(s)orauxiliarydieselengine(s)totherelevant generating unit must be started, and must re-energise the unit board of the relevant generating unit.

• The auxiliaries of the relevant generatingunitmust be fedbythe auxiliary gas turbine(s) or auxiliary diesel engine(s), via the unit board, to enable the relevant generating unit to return to synchronous speed.

• Therelevantgeneratingunitmustbesynchronisedtothesystembut not loaded, unless the appropriate instruction has been given by the transmission company.

Allblackstarttestsmustbecarriedoutatthetimespecifiedbythetransmission company in the notice given under 2.2.1.8 and must be undertaken in the presence of a reasonable number of representatives appointed and authorised by the transmission company, who must be given access to all information relevant to the black start test.

ACCEPTANCE CRITERIA

A black start station must fail a black start test if the black start test shows that it does not have a black start capability (i.e. if the relevant generating unit fails to be synchronised to the system within two hours of the auxiliary gas turbine(s) or auxiliary diesel engine(s) being required to start).



Parameter Reference

Station black starting

APPLICABILITY

Routine test: All stations contracted under ancillary services to provide a station black start service. When called for by the transmission company but not more than once every two years

PURPOSE

Demonstrate that a black start station has a black start capability.

PROCEDURE

• All generating units at the black start station, other than thegenerating unit on which the black start test is to be carried out, and all the auxiliary gas turbines and auxiliary diesel engines at the black start station, must be shutdown.

• Therelevantgeneratingunitmustbesynchronisedandloaded.• the relevant generating unit must be de-loaded and de-

synchronised.• All external alternating current electrical supplies to the unit

board of the relevant generating unit, and to the station board of the relevant black start station, must be disconnected.

• Anauxiliarygasturbineorauxiliarydieselengineattheblackstart station must be started, and must re-energise either directly, or via the station board, the unit board of the relevant generating unit.

• The auxiliaries of the relevant generatingunitmust be fedbythe auxiliary gas turbine(s) or auxiliary diesel engine(s), via the unit board, to enable the relevant generating unit to return to synchronous speed.

• Therelevantgeneratingunitmustbesynchronisedtothesystembut not loaded, unless the appropriate instruction has been given by the transmission company.

Allblackstarttestsmustbecarriedoutatthetimespecifiedbythetransmission company in the notice given under 2.2.1.8 and must be undertaken in the presence of a reasonable number of representatives appointed and authorised by the Transmission company, who must be given access to all Information relevant to the Black Start Test.

ACCEPTANCE CRITERIA

A black start station must fail a black start test if the black start test shows that it does not have a black start capability (i.e. if the relevant generating unit fails to be synchronised to the system within two hours of the auxiliary gas turbine(s) or auxiliary diesel engine(s) being required to start).



(9) Unit intermediate load capability grid code requirement GCR 11


Intermediate load capability

APPLICABILITY

Prototype study: All new power stations coming on line or power stations where major refurbishment or upgrade of the unit have taken place.


PURPOSE

Prove unit can meet the minimum requirements of the Transmission Grid Code

PROCEDURE

1. A section of the unit is to be tripped that will cause a 15% of MCR reduction of the output of the Unit. Should nothing be found to induce this reduction a sudden reduction of the Unit output must be done manually.

2. The plant is to be monitored and recorded to ensure the plant continues to operate in a stable and controlled mode after the reduction.

ACCEPTANCE CRITERIA

The unit must be in a stable and controlled mode after the trip or reduction in the Unit output.

(10) External supply disturbance withstand capability grid code requirement GCR 12

Parameter ReferenceVoltage and frequency deviation

APPLICABILITY

Prototype survey or test: new power stations coming on line or powerstationswheremajormodificationstoplantthatmaybecriticalto system supply frequency or voltage magnitude deviations. Criteria 1to4forplantsusingDipProofingInverters(DPI)

Routine testing and survey: All power stations. Review items 1 to 3 every 5 to 6 years. Carry out item 5 every 5 to 6 years.

PURPOSE

To confirm that the power station and its auxiliary supply loadsconforms to the requirements of supply frequency and voltage magnitudedeviationsasspecified(tobedetermined).

SCOPE OF PLANT OR SYSTEMS

Critical plant: Equipment or systems that is likely to cause tripping of a unit, parts of a unit or that is likely to cause a multiple unit trip (MUT).


PROCEDURE AND ACCEPTANCE CRITERIA

1. Frequency deviation survey:Carryoutasurveyonthecapabilityofcriticalplantconfirmingthatitwillresumenormaloperationforfrequencydeviationsasdefinedfigure2.2.1.6.Documentfindings.

A generating unit or power station must not trip or unduly reduce load forsystemfrequencychangesintherangespecifiedin2.2.1.6.

2. Voltage magnitude deviation survey:

Carryoutasurveyonthecapabilityofcriticalplantconfirmingthatit will resume normal operation for voltage deviations as definedin 2.2.1.6. Document Findings. Also consider protection and other trippingfunctionsoncriticalplant.Documentallfindings.

A generating unit or power station must not trip or unduly reduce load forsystemvoltagechangesintherangespecifiedin2.2.1.6.

3. Dip proofing inverter integrity testing:• Generatingunitmustbeoffload.Relevantboardisolatedand

earthed. For outside or central plant, section of plant must be off boards off and isolated.

• InjectiontestDPIsaccordingtoOEMrequirements.DPImustbe capable of producing the VA Output and change-over time fasterthanthatspecifiedbytheOEM.Everyfiveyearsoneverycritical board.

• IsolateallDrivesontheboard.• Selectalldrivestomanualorlocalcontrol.• SupplyanindependentACsupplytotheinputoftheDPI.• Closethecontractorsofdrives.• SubjecttheDPIsupplytoaninterruptionof0.5s.

Document all results.

All contractors must remain closed.

Report to be submitted to the transmission company one month after testing. Routine studies, and survey reports to be submitted one month after expiry of due date.


(11) Unit load and de-loading rate capability grid code requirements GCR 13


Loading and de-loading rates.

TYPE

Prototype study: All new power stations coming on line or power stations where major refurbishment or upgrade of the unit have taken place.


PURPOSE

Prove unit can meet the minimum requirements of the Transmission Grid Code.

PROCEDURE

1. The Unit is to be ramped up and down.2. The plant is to be monitored and recorded to ensure the plant

continues to operate in a stable and controlled mode during and after the ramps.

ACCEPTANCE CRITERIA

The unit must be ramped up and down in a stable and controlled mode and must meet the minimum requirements of the Transmission Grid Code.


ANNEXURE 5

VOLTAGE TOLERANCES FOR VARIOUS FREQUENCY RANGES


ANNEXURE 6

TABLE 1: SELECTION OF DEAD LINE CHARGING END OF THE LINE

End AEnd B Substation FL<10kA Substation FL>10kA Power Station

Substation FL<10kA Substation with higher FL Substation A Substation B

Substation FL>10kA Substation B Substation with lower FL Substation B

Power Station Substation A Substation A Power Station with lower FL


ANNEXURE 7

SAMPLE CONFIDENTIALITY AGREEMENT FOR INFORMATION TRANSFER TO THIRD PARTIES

CONFIDENTIALITY AGREEMENTBETWEEN

....................................................................................................................(HEREINAFTER REFERRED TO AS THE INFORMATION OWNER)AND....................................................................................................................(HEREINAFTER REFERRED TO AS THE RECIPIENT)IN RESPECT OF INFORMATION SUPPLIED TO PERFORM THE FOLLOWING WORK:

...............................................................................................................................................................

...............................................................................................................................................................

(HEREINAFTER REFERRED TO AS THE WORK)ON BEHALF OF

....................................................................................................................(HEREINAFTER REFERRED TO AS THE CLIENT).

(1) The Recipient agrees to treat all information (hereinafter referred to as the Information) received from the Information Owner, whether in hard copy or electronic format, as strictly confidential.

(2) The Recipient agrees to disclose the Information only to persons who are in his or her permanent employ, and who require access to the Information to perform their duties in respect of the Work on behalf of the Client.

(3) Persons other than those described in Clause 2 above, including but not restricted to temporary employees, subcontractors, and sub-consultants, shall enter into separate ConfidentialityAgreements with the Information Owner prior to receiving the Information.

(4) The Recipient undertakes to use the Information only to perform the Work on behalf of the Client, and for no other purpose whatsoever.

(5) On completion of the Work, the Recipient shall at his or her own expense return to the Information Owner all hard copy material and computer disks containing the Information supplied to him by the Information Owner. The Recipient shall furthermore ensure that all duplicate copies of the Information in his or her, or his or her employees’, possession (electronic as well as hard copy format) are destroyed.

(6) The Recipient shall take all reasonable measures to protect the Security and integrity of the Information.

(7) If requested to do so by the Information Owner, the Recipient shall forthwith at his or her expense return to the Information Owner all hard copy material and computer disks containing the Information supplied to him by the Information Owner. The Recipient shall furthermore ensure that all duplicate copies of the Information in his or her, or his or her employees’, possession (electronic as well as hard copy format) are destroyed.


(8) The Recipient shall report any leak of the Information, howsoever caused, to the Information Owner as soon as practicable after he becomes aware of the leak, and shall provide to the Information Owner with all reasonable assistance to ensure its recovery or destruction (as deemed appropriate by the Information Owner).

Signed at ................................................................................... on this the .................. day of .............................................................................. by (full name) .............................................................................. in his/her capacity as .............................................................................. on behalf of .............................................................................., the Information Owner

..............................................................................

Signed at ................................................................................... on this the .................. day of .............................................................................. by (full name) .............................................................................. in his/her capacity as .............................................................................. on behalf of .............................................................................., the Recipient

..............................................................................


ANNEXURE 8

Distributor and end-use customer data

Unless otherwise indicated, the following information shall be supplied to the transmission company, prior to connection and then updated as and when changes occur.

1. Demand data

Connection capacity Connection capacity required (MW)Measured and forecast data (annually)

For each Point of Supply, the information required is as follows:• A5-yeardemandforecast.(SeeAnnexure15).• Adescriptionsettingoutthebasisfortheforecast.• Theseasonofpeakdemand• Quantificationoftheestimatedimpactofembeddedgeneration.(SeeAnnexure

15)• A10-yeardemandestimate

User network data • Electricalsingle-linediagramofusernetworktoalevelofdetailtobeagreedwith the service- providers, including the electrical characteristics of circuits and equipment (R, X, B, R0, X0, B0, continuous and probabilistic ratings).

• Contributionfromcustomer network to a three-phase short circuit at Point of Connection.

• Connectiondetailsofallcustomer transformers, shunt capacitors, shunt reactors etc. connected to the secondary voltage levels of the customer connected the TS. (the requirement here is for data pertaining to the network connecting shuntcapacitors,harmonicfilters,reactors,SVCs,etc.tothePoint of Supply for purposes of conducting harmonic resonance studies.)

• Electricalcharacteristicsofallcircuitsandequipmentatavoltagelowerthansecondary voltage levels of the customer connected the TS that may form a closed tie between two connection points on the TS.

Standby supply data (annually)

The following information is required for each distributor and end-use customer that can take supply from more than one supply point:• Sourceofstandbysupply(alternativesupplypoint(s))• Standbycapacityrequired(MW)

General information For each new connection from a distributor or end-use customer, the following information is required:• Numberandtypeofswitchbaysrequired• Loadbuild-upcurve(inthecaseofnewend-userplant)• Supplydate(startofloadbuild-up)• Temporaryconstructionsupplyrequirements• Loadtype(e.g.ARCfurnaces,rectifiers,rollingmills,residential,commercial,

etc.)• Annualloadfactor• Powerfactor(includingdetailsofharmonicfiltersandpowerfactorcorrection

capacitors)Special requirements (e.g. quality of supply)Other information reasonably required by the service-providers to provide the customer with an appropriate supply (e.g. pollution emission levels for insulation design)

Disturbing loads Description of any load on the power system that could adversely affect the System Operator target conditions for power quality and the variation in the power quality that can be expected at the point connected to the TS. (The areas of concern here are,firstly,motorswithstartingcurrentsreferredbacktothenominalvoltageatthePoint of Supply exceeding 5% of the fault level at the Point of Supply and secondly, ARC furnaces likely to produce flicker levels at the Point of Supply in excess of thelimitsspecifiedinNRS048.ThesizelimitforARC furnaces is subject to local conditions in respect of fault level at the Point of Supply and background flicker produced by other ARC furnaces.)


2. Transmission system connected transformer data

Symbol UnitsNumber of windingsVector groupRated current of each winding ATransformer rating MVATrans

Transformer tertiary rating MVATransformer nominal LV voltage kVTransformer nominal tertiary voltage kVTransformer nominal HV voltage kVTapped winding HV/MV/LV/None (Delete

what is not applicable)Transformer ratio at all transformer tapsTransformer Impedance (resistance R and reactance X) at all taps

R+jX % on rating MVATrans

For three-winding transformers, where there are external connections to all three windings, the impedance (resistance R and reactance X) between each pair of windings is required, measured with the third set of terminals open-circuit.

ZHVMV, ZHVLV, & ZMVLV

% on rating MVATrans% on rating MVATrans% on rating MVATrans

Transformer zero sequence impedances at nominal tapZero phase sequence impedance measured between the HV terminals (shorted) and the neutral terminal, with the LV terminals open-circuit.

ZHT 0 Ohm

Zero phase sequence impedance measured between the HV terminals (shorted) and the neutral terminal, with the LV terminals short-circuited to the neutral.

ZHL 0 Ohm

Zero phase sequence impedance measured between the LV terminals (shorted) and the neutral terminal, with the HV terminals open-circuit.

ZLT 0 Ohm

Zero phase sequence impedance measured between the LV terminals (shorted) and the neutral terminal, with the HV terminals short-circuited to the neutral.

ZLH 0 Ohm

Zero phase sequence leakage impedance measured between the HV terminals (shorted) and the LV terminals (shorted), with the Delta winding closed.

ZL 0 Ohm

Earthing arrangement, including LV neutral earthing resistance and reactance core construction (number of limbs, shell or core type)Open circuit characteristic Graph

Transformertestcertificates,fromwhichactualtechnicaldetailcanbeextractedasrequired,aretobe supplied on request.

3. Shunt capacitor or reactor data requirements

(1) For each shunt capacitor or reactor or power factor correction equipment or harmonic filterswitharatinginexcessof1MVArconnectedtoorcapableofbeingconnectedto a customer network, the customer shall inform the Transco and, if required, shall provide the Transcowiththespecificshuntcapacitororreactordata as well as network details necessary to perform primarily harmonic resonance studies. The customer shall inform the Transco of his intention to extend or modify this equipment.


(2) If any Participantfindsthatacapacitorbankof1MVArorlessis likelytocauseharmonic resonance problems on the TS, he shall inform the Transco. The 1MVAr minimum size limit shall thereafter be waived in respect of the affected network for information reporting purposes in respect of this code, and the Transco shall inform the affected Participants of this fact and request the additional data. If the affectednetworkismodifiedorreinforcedto theextent thatcapacitorbanksof1MVAr or less no longer cause harmonic resonance problems on the TS, the Transco shall inform the affected Participants that information reporting requirements have returned to normal.

(3) Any Party to this code investigating a complaint about harmonic distortion, shall have the right to request such additional information (including, but not restricted to, data from harmonic distortion measuring devices) from parties in the vicinity of the source of the complaint as may reasonably be required to complete the investigation.

Shunt capacitor or reactor rating Rating (MVAr)

Reactor/capacitor/harmonicfilter (delete what is not applicable)Location (station name)Voltage rating kVResistance/reactance/susceptance of all components of the capacitor or reactor bankFixed or switchedIf switched Control details (manual, time, load, voltage, etc.)If automatic control Details of settings. If under FACTS device control

(e.g. SVC), which device?

4. Series capacitor or reactor data requirements

(1) Series capacitors are installed in long Transmission lines to increase load transfer capability.

(2) Series reactors are installed to limit fault levels, or to balance load sharing between circuits operated in parallel that would otherwise not share load equitably, or to balance load sharing on an interconnected network.

Reactor/capacitor (Delete what is not applicable)Location (specify Substation bay where applicable)Voltage rating kVImpedance rating Ohm or MVArCurrent rating (continuous and emergency, maximum times for emergency ratings)

Continuous: A Hours A Hours A Hours A

(3) Note: if a series capacitor or reactor is located in a dedicated reactor or capacitor station (i.e. a Substation built to hold only the series reactor or capacitor), the lines or cables linking it to each remote end Substationmustbespecifiedasseparatecircuitsunder line or cable data.


5. FACTS devices and HVDC data

5.1 FACTS devices

(1) FACTS devices enable system parameters (voltage, current, power flow) to beaccurately controlled in real time. Because of their cost, they are generally used only if cheaper, more conventional, solutions cannot deliver the required functionality.

(2) Applications requiring rapid control capability include the following:

(a) Voltage regulation following loss of a system component, generation, large load, or HVDC link disturbance;

(b) automaticreclosingcyclefurnacevoltageflickermitigation;

(c) Negative phase sequence voltage compensation;

(d) Sub-Synchronous Resonance (SSR) damping;

(e) Machine transient stability enhancement;

(f) System load transfer capability enhancement; and

(g) Load sharing control in interconnected, deregulated, networks.

(3) The most commonly used FACTS device is the SVC (static Var compensator). Other FACTS devices made possible by advances in power electronics and control systems include STATCON (static condenser), TCSC (thyristor controlled series capacitor), thyristor controlled tap changer, thyristor controlled phase shifter, BES (battery energystorage),andUPFC(unifiedpowercontroller).Thecommonfactorisrapidcontrol capability.

(4) Because FACTS devices are purpose-designed for their specific applications, thefollowing data is required:

Name Station, HV voltage, device numberType (SVC, STATCON, TCSC, etc.)Configuration: Provide a single line diagramshowing all HV components and their MVA/MVAr and voltage ratings, with all controlled componentsidentifiedassuch.Control system: Provide a block diagram of the control system suitable for dynamics modelling.Primary control mode Voltagecontrol,automaticreclosingcyclefurnaceflicker

mitigation, negative phase sequence voltage control, etc.

(5) Customers are required to perform, or cause to be performed, harmonic studies to ensure that their installation does not excite harmonic resonance, and that harmonic distortion levels at the PCC with the TSdonotexceedthelimitsspecifiedinNRS048.

5.2 HVDC

(1) Strictly speaking, HVDC is a form of FACTS device because of the rapid control capabilities. However, HVDC is treated separately because its primary function is the Transmission of real power.


(2) HVDC is used to connect two systems that are not necessarily interconnected via the AC network (and thus in synchronism), or even at the same nominal frequency.

(3) Customers wishing to connect HVDC systems to the TS shall supply a single line diagram showing all HV plant (including valve bridges) forming part of the HVDC system, plus additional HV plant required for its proper operation, e.g. harmonic filters, synchronous condensers,FACTS devices, etc. Customers and the Transco shall cooperate in performing, or causing to be performed, studies to determine network strengthening requirements needed to accommodate the HVDC system withoutviolatingtheplanningcriteriaspecifiedintheNetworkCode.Inaddition,customers shall thereafter perform, or cause to be performed, studies to demonstrate that the proposed HVDC system does not cause exceedance of QOS parameters specifiedinNRS048,andwhereapplicableshallspecifywhatadditionalHV plant will be required to ensure compliance with NRS048.

6. Information on customer networks

(1) If a customer will have two or more points of supply from the TS, including the one applied for, the customer shall specify the amount of load to be transferred from existing points of supply to the new one under normal conditions as well as under contingencies. The same requirement applies to any embedded generators within the customer’s network, since they affect fault levels as well as net load on the system.

(2) The customer shall also specify whether he intends to interconnect two or more Transmission points of supply via his network. In such circumstances the customer shall provide detailed information on the lines and cables used.

(3) Where a circuit consists of two or more segments of different characteristics (different overhead line tower and/or conductor bundle types and/or underground cabletypes),eachsectionshallbespecifiedseparately.

7. Overhead line data

UnitsLine description Name (“from” Busbar, “to” Busbar, circuit

number and, where applicable, line section number numbered from the “from” bus end)

Line voltage (specify separately for dual voltage multi-circuit lines)

kV

Single / double / multiple circuitStandard suspension tower information (to confirmimpedance): Supply copy of tower drawing, or sketch drawing showing co-ordinates of shield wire and phase conductor bundle attachment points relative to tower centre line and ground level at nominal tower height.Phase sub-conductor type (per circuit)Number of sub-conductors per phase conductor bundle Sub-conductor spacing, if applicable (supply sketch showing phase conductor bundle geometry and attachment point)

mm

Number of earth wiresEarth wire descriptionLine length kmConductor parameters (R, X, B, R0, X0, B0) Ohmic values or P.U. on 100MVA base

(specify)Conductor normal and emergency ratings Ampere or 3 phase MVA at nominal voltage


8. Cable data

Cable description Name (“from” Busbar, “to” Busbar, circuit number, and where applicable, line section number numbered from the “from” bus end)

Voltage rating kVType (copper/aluminium) (Delete what is not applicable)Size mm2

Impedance (R, X, B, R0,X0,B0) Ohms or P.U. on 100MVA base (specify)Length kmContinuous and (where applicable) emergency current rating and time limit

Amp or MVA at nominal voltage (specify), hours maximum at emergency rating


ANNEXURE 9

Generator planning data

Unless otherwise indicated, the following information shall be provided to the transmission company prior to connection and then updated as and when changes occur.

1. Power Station data

Generator namePower Station nameNumber of unitsPrimary fuel type / prime mover For example gas, hydro, fossil or nuclearSecondary fuel type For example oilCapacity requirement Generation sent-out connection capacity required (MW)“Restart after station blackout” capacity

Provide a document containing the following:Start-uptimeforthefirstGenerating Unit (time from restart initiation to synchronize) and each of the following units assuming that restarting of units will be staggered.

Black starting capacity A document stating the number of units that can be black started at the sametime,preparationtimeforthefirstGenerating Unit black starting restarting timefor thefirstGenerating Unit, and restating time for the rest of the units.

Partial load rejection capability A description of the amount of load the Generating Unit can automatically govern back, without any restrictions, as a function of the load at the point of governing initiation.

Multiple generating unit tripping (MUT) risks

A document outlining all systems common to more than one Generating Unit that is likely to cause a MUT. Discuss the measures taken to reduce the risk of MUT.

2. Generating unit data

Generating Unit numberCapacity Generating Unit capacity (MW)

UnitsNormal maximum continuous generation capacity: MWNormal maximum continuous sent out capacity MWGenerating Unit auxiliary active load MWGenerating Unit auxiliary reactive load MVArMaximum (EL1) generating capacity MWMaximum (EL2) sent out capacity MWNormal minimum continuous generating capacity MWNormal minimum continuous sent out capacity MWGenerator rating (Mbase) MVANormal maximum lagging power factor MVArNormal maximum leading power factor MVArGovernor droopForbidden loading zones MWTerminal voltage adjustment range kVShort circuit ratioRated stator current Amp


Time to synchronise from warm HourTime to synchronise from cold HourMinimum up-time HourMinimum down-time HourNormal loading rate MW/minNormal de-loading rate MW/minCan the generator start on each fuel?Ability to change fuels on-loadAvailable modes (lean burn etc.)Time to change modes on-loadControl range for secondary frequency regulation operation MWPartial load rejection capability % MW name plate ratingMinimum time Generating Unit operates in island mode HourMaximum time Generating Unit operates in island mode Hour

Description DataCapability chart showing full range of operating capability of the generator, including thermal and excitation limits

Diagram

Systems that are common and can cause a multiple Generating Unit trip DescriptionOpen circuit magnetisation curves GraphShort circuit characteristic GraphZero power factor curve GraphV curves Diagram

Documents DescriptionProtection setting document

A document agreed and signed by the System Operator containing the following:• AsectiondefiningthebasevaluesandperGenerating Unit values to be used• A single line diagram showing all the Protection functions and sources of current

and voltage signals• A Protection tripping diagram(s) showing all the Protection functions and

associated tripping logic and tripping functions• A detailed description of setting calculation for each Protection setting, discussion

on Protection function stability calculations, and detailed dial settings on the Protection relay in order to achieve the required setting

• A section containing a summary of all Protection settings on a per Generating Unit basis

• A section containing a summary for each of the Protection relay dial settings/programming details

• An annex containing plant information data (e.g. OEM data) on which the settings are based

• An annex containing OEM information sheets or documents describing how the Protection relays function


Excitation setting document

A document agreed and signed by the System Operator containing the following:• AsectiondefiningthebasevaluesandperGenerating Unit values to be used

• A single line diagram showing all the excitation system functions and all the related Protection tripping functions

• An excitation system transfer function block diagram in accordance with IEEE or IEC standard models

• A detailed description of setting calculation for each of the excitation system functions, discussion on function stability calculations, and detailed dial settings on the excitation system in order to achieve the required setting

• A section containing a summery of all settings on a per Generating Unit basis• A section containing a summary for each of the excitation system dial settings/

programming details.• An annex containing plant information data (e.g. OEM data) on which the

settings are based• An annex containing OEM information sheets or documents describing the

performance of the overall excitation system and each excitation function for which a setting is derived

Governor setting document

A document agreed and signed by the System Operator containing the following:• AsectiondefiningthebasevaluesandperGenerating Unit values to be used

• A single line diagram showing all the excitation system functions and all the related Protection tripping functions

• An excitation system transfer function block diagram in accordance with IEEE standard models

• A detailed description of setting calculation for each of the governor system functions, discussion on function stability calculations, and detailed dial settings on the governor system in order to achieve the required setting

• A section containing a summary of all settings on a per Generating Unit basis• A section containing a summary for each of the governor system dial settings/

programming details • An annex containing plant information data (e.g. OEM data) on which the

settings are based• An annex containing OEM information sheets or documents describing the

performance of the overall governor system and each governor function for which a setting is derived

3. Reserve capability

The generator shall provide the System Operator with the reserve capability of each Generating Unit at each Power Station. The reserve capability shall be indicated as per each reserve category: instantaneous reserve, Regulating Reserve, emergency reserve, 10 minute reserve and supplemental reserve.

4. Generating unit parameters

Symbol Units

Direct axis synchronous reactance X d % on rating

Direct axis transient reactance saturated X satd'

% on rating

Direct axis transient reactance unsaturated X unsatd'

% on rating

Sub-transient reactance unsaturated XX qd""

= % on rating

Quad axis synchronous reactance X q % on rating


Quad axis transient reactance unsaturated X unsatq'

% on rating

Negative phase sequence synchronous reactance X 2 % on rating

Zero phase sequence reactance X q0 % on rating

Turbine generator inertia constant for entire rotating mass H MW s/MVAStator resistance Ra % on rating

Stator leakage reactance X L % on rating

Poiter reactance X P % on rating

Generator time constants:· Direct axis open-circuit transient· Direct axis open-circuit sub-transient· Quad axis open-circuit transient· Quad axis open-circuit sub-transient· Direct axis short-circuit transient· Direct axis short-circuit sub-transient· Quad axis short-circuit transient· Quad axis short-circuit sub-transient

Tdo’Tdo’’Tqo’ Tqo’’Td’Td’’Tq’Tq’’

secsecsecsecsecsecsecsec

Speed damping DSaturation ratio at 1 pu terminal voltage S(1.0)Saturation ratio at 1.2 pu terminal voltage S(1.2)

5. Excitation system

(1) The generator shall fill in the following parameters or supply aLaplace-domaincontrol block diagram in accordance with IEEE or IEC standard excitation models (or as otherwise agreed with the System Operator) completely specifying all time constants and gains to fully explain the transfer function from the compensator or Generating UnitterminalvoltageandfieldcurrenttoGenerating Unitfieldvoltage.Customers shall perform, or cause to be performed, small signal dynamic studies to ensure that the proposed excitation system and turbine governor do not cause dynamic instability. Where applicable, a PSS (power system stabiliser) shall be included in the excitation system to ensure proper tuning of the excitation system for stability purposes.

Symbol UnitsExcitation system type (AC or DC) TextExcitation feeding arrangement (solid or shunt) TextExcitationsystemfiltertimeconstant Tr secExcitation system lead time constant Tc secExcitation system lag time constant Tb secExcitation system controller gain KaExcitation system controller lag time constant Ta secExcitation system maximum controller output Vmax P.U.Excitation system minimum controller output Vmin P.U.Excitation system regulation factor KcExcitation system rate feedback gain KfExcitation system rate feedback time constant Tf sec


6. Speed governor system, turbine and boiler models

The generator shall supply a Laplace domain control block diagram in accordance with IEEE standard prime mover models for thermal and hydro units (or as otherwise agreed with the Transco), fully specifying all time constants and gains to fully explain the transfer function for the governor, turbine, penstocks and control systems in relation to frequency deviations and set-point operation.

7. Control devices and protection relays

The generator should supply any additional Laplace domain control diagrams for any outstanding control devices (including power system stabilisers) or special Protection relays in the Generating Unit that automatically impinge on its operating characteristics within 30 seconds following a system disturbance and that have a minimum time constant of at least 0,02 seconds.

8. Pumped storage

Symbol UnitsReservoir capacity MWh pumpingMax pumping capacity MWMin pumping capacity MWEfficiency(generating/pumpingratio) %

9. Generating unit step-up transformer

Symbol UnitsNumber of windingsVector groupRated current of each winding AmpsTransformer rating MVATrans

Transformer nominal LV voltage kVTransformer nominal HV voltage kVTapped windingTransformer ratio at all transformer tapsTransformer impedance at all taps(For three winding transformers the HV/LV1, HV/LV2 and LV1/LV2 impedances together with associated bases shall be provided)

% on rating MVATrans

Transformer zero sequence impedance at nominal tap Z 0Ohm

Earthing arrangement, including neutral earthing resistance and reactanceCore construction (number of limbs, shell or core type)Open circuit characteristic Graph

10. Generating unit forecast data

The generator shall provide the Transco with expected maintenance requirements, in weeks per annum, for each Generating Unit at a Power Station.


11. Mothballing of generating plant

Mothballing of generating plant is the withdrawal of plant from commercial service for six Months or longer, with the intention of returning it to commercial service at a later date. Mothballing can have a profound impact on the operation and integrity of the TS. Customers wishing to mothball generating plant shall supply the Transco with the following information:

Generator namePower Station nameGenerating Unit numberDate withdrawn Date Generating Unit is to be withdrawn from

commercial serviceReturn to commercial service Envisaged return to service date (re-commissioning

tests completed and Generating Unit available for commercial service)

Auxiliary power requirements

12. Return to service of mothballed generating plant

Once the customer has decided to return mothballed generating plant to service, the Transco requirestheinformationspecifiedfornewconnections.

13. Decommissioning of generating plantDecommissioning of plant is the permanent withdrawal from service of generating plant. The Transco requires the following with a one-year notice period:

Generator namePower Station nameGenerating Unit numberDate to be removed from commercial serviceAuxiliary supplies required for dismantling and demolition

kVA, point at which supply is require, duration


ANNEXURE 10

Generator maintenance data

(1) The 52-weeks-ahead outage plan per week per generator shall be supplied weekly to the System Operator.

Generator:DATE (week starting) WEEK NUMBER: n n+1 … n+51

MAINTENANCE (MW)WEEKEND OUTAGES 0 0 0 0Power Station 1 0 0 0 0Power Station 2 0 0 0 0Power Station 3 0 0 0 0Power Station n 0 0 0 0TOTAL MAINTENANCEFUTURE KNOWN UNPLANNED: 0 0 0 0

MAJOR CHANGES SINCE LAST WEEK:

Notes:

FUTURE KNOWN UNPLANNED : a)b)

(2) The annual maintenance/outage plan per generator,lookingfiveyearsahead,shallbe supplied to the System Operator.

(3) The format shall be as per the 52-weeks-ahead outage plan per week per generator, butextendingforfiveyears.

(4) A monthly variance report, explaining the differences between the above two reports, shall be supplied to the System Operator.

Variance Report Template

Station and MW Start-Date Outage Completion-DateOutage Code Cap Official Official Revised Urg Outage

DescriptionReason for Difference


ANNEXURE 11

Operational data

(1) ThisAnnexurespecifiesthedata format to be used by the SCADA system for the mapping of RTU data into the SCADA database. The databasehasadefinitionforeach electrical configuration (ELC) or electrical object in the station. EachELCdefinitionspecifiesadifferentELCtype,e.g.transformers,units,feeders,etc,andis accompanied by a picture showing the ELC and all its associated devices as they would be indicated on the System Operator operational one-line displays. In eachinstance,thepicturedefinestheprimarydevicesandisfollowedbythepointsbelonging to each device.

(2) Description of table column headings used in this section:

Device 01_State 10_State Category Type Control

Device Gives the name of the device and acts as a collector of all point information belonging to the device. Each binary status point can be mapped to one or two binary bits. In the case of a breaker or isolator, the state is reported via two bits. In the case of single-bit alarm points, only one bit is used to report the state of the indication.

01_state This is the alarm state of the point.

10_state This is the normal state of the point.

In the table below the TYPE column indicates the number of bits used to report the state of the point in question.

For single-bit points please ignore the left-hand 0 or 1 value in the headings “01-State” and “10-State”.Where an indication uses two bits to report the state, the right-hand bit is used report that the state is OPEN and the left-hand bit to report the state when it is CLOSED. Thus an open condition will be “01” and a closed state will be “10”.

It is thus illogical for a device to have a permanent value of either “00” or “11”. However, if the device is in transit between “01” and “10” then a temporary value of “00” is possible. The SCADA system reports a state of “00” as “In transit”, which will normally only be seen on slow-moving devices such as isolators.

Category Defines the category the point belongs to: Health, Main Protection, Back-up Protection or Information.

Classical alarm systems attempt to set priorities on alarm points. However, the priority of a point changes as the system changes, whichmeans having a fixedpriority is not useful. As an alternative, the approach used here is to assign the point to the area that is affected by the indication. In this case we have four areas, namely:

Health All alarm indications that refer to the health of the primary or secondary plant are assigned to this category.

Main Protection All Protection activity that is triggered by the Main 1 Protection circuits is assigned to this category.


Backup Protection Where back-up Protection is installed, such as on transformers, or where Main 2 Protection is used, these alarms are assigned to this category.

Information Pure state change data such the state of a breaker or isolator are assigned to this category. As such, no alarming is associated with these points – the data presented is pure information.

Type Indicates the type of point – single-bit, double-bit, analogue or binary change detection.

Control Indicates if there is a supervisory control associated with the point

1. Generator

The generator shall install operational measurements to specification from the systemoperator so as to provide continuous operational information for both real time and recording purposes in relation to each generating unit at each power station in respect of the following:

(1) Gas turbines

Generating Unit Isolator 01_State 10_State Category Type ControlPole Disagree Normal Health Single FalseGenerating Unit isolator state Open Closed Info Double FalseGenerating Unit HV Breaker 01_State 10_State Category Type ControlBreaker failed to trip Alarm Normal Main Single FalseBus zone trip Alarm Normal Info Single FalseEarth applied Alarm Normal Health Single FalsePole Disagree Normal Health Single FalseProtection abnormal Alarm Normal Health Single FalseProtection operated Alarm Normal Main Single FalseProtection unhealthy Alarm Normal Health Single FalseBreaker gas critical Alarm Normal Health Single FalseBreaker non-urgent Alarm Normal Info Single FalseGenerating Unit breaker state Closed Tripped Info Double FalseCurrent Transformer 01_State 10_State Category Type ControlSF6 gas critical (CT) Alarm Normal Health Single FalseSF6 non-critical (CT) Alarm Normal Health Single FalseGenerating Unit Step Up Transformer

01_State 10_State Category Type Control


Reactive power Info Analogue FalseActive power Info Analogue FalseGenerating Unit LV Breaker 01_State 10_State Category Type ControlBreaker failed to trip Alarm Normal Main Single FalseEarth applied Alarm Normal Health Single FalsePole Disagree Normal Health Single FalseBreaker gas critical Alarm Normal Health Single FalseBreaker non-urgent Alarm Normal Info Single FalseGenerating Unit breaker state Closed Tripped Info Double FalseGenerating Unit 01_State 10_State Category Type ControlEngine A Ready Not ready Health Single FalseEngine B Ready Not ready Health Single FalseFrequency Info Analogue FalseGenerating Unit start not ready

Alarm Normal Health Single False

Remote control On Off Info Single TrueSCO start not ready Alarm Normal Health Single FalseSequence starting Auto Manual Info Single FalseStator voltage Info Analogue FalseSupervisory Isolated Off Info Single FalseUnder-frequency start Armed Off Health Single FalseGenerating Unit at standstill Yes Normal Info Single TrueGenerating Unit auto load to base

Yes No Info Single True

Generating Unit auto load to minimum


Generating Unit auto load to peak


Generating Unit failed to start Alarm Normal Health Single FalseGenerating Unit voltage Info Analogue FalseGenerating Unit in generation mode


Generating Unit in SCO mode Yes No Info Single TrueGenerating Unit load rate Fast Slow Info Single TrueGenerating Unit loading mode

Auto Manual Info Single False

Generating Unit reactive power generated

Info Analogue False

Generating Unit reactive power sent out

Info Analogue False

Generating Unit active power generated

Info Analogue False

Generating Unit active power sent out

Info Analogue False

Generating Unit tripped and locked out

Alarm Normal Info Single False

Generating Unit under frequency start

Initiate No Info Single False


(2) Hydro units

Generating Unit Isolator 1 01_State 10_State Category Type ControlPole Disagree Normal Health Single FalseGenerating Unit isolator state Open Closed Info Double FalseGenerating Unit Isolator 2 01_State 10_State Category Type ControlPole Disagree Normal Health Single FalseGenerating Unit isolator state Open Closed Info Double FalseGenerating Unit HV Breaker 01_State 10_State Category Type ControlBreaker failed to trip Alarm Normal Main Single FalseBus zone trip Alarm Normal Info Single FalseEarth applied Alarm Normal Health Single FalsePole Disagree Normal Health Single FalseProtection abnormal Alarm Normal Health Single FalseProtection operated Alarm Normal Main Single FalseProtection unhealthy Alarm Normal Health Single FalseBreaker gas critical Alarm Normal Health Single FalseBreaker non-urgent Alarm Normal Info Single FalseGenerating Unit breaker state Closed Tripped Info Double FalseCurrent Transformer 01_State 10_State Category Type ControlSF6 gas critical (CT) Alarm Normal Health Single FalseSF6 non-critical (CT) Alarm Normal Health Single FalseGenerating Unit LV Breaker 01_State 10_State Category Type ControlBreaker failed to trip Alarm Normal Main Single FalseEarth applied Alarm Normal Health Single FalsePole Disagree Normal Health Single FalseBreaker gas critical Alarm Normal Health Single FalseBreaker non-urgent Alarm Normal Info Single FalseGenerating Unit breaker state Closed Tripped Info Double FalseGenerating Unit Step Up Transformer


Reactive power Info Analogue FalseActive power Info Analogue False


Isolator 3 01_State 10_State Category Type ControlPole Disagree Normal Health Single FalseGenerating Unit isolator state Open Closed Info Double FalseIsolator 4 01_State 10_State Category Type ControlPole Disagree Normal Health Single FalseGenerating Unit isolator state Open Closed Info Double FalseGenerating Unit 01_State 10_State Category Type ControlFrequency Info Analogue FalseAuto load Active Normal Info Single TrueAutomatic power factor regulator

Operated Normal Health Single True

Emergency trip Operated Normal Main Single TrueGenerating Unit start not ready

Alarm Normal Health Single False

Generating Unit to pump mode

Active Off Info Single True

Generating Unit to SCO mode Active Off Info Single TruePump start not ready Alarm Normal Health Single FalsePump to generation mode Active Off Info Single TruePump to SCO mode Active Off Info Single TrueSCO start not ready Alarm Normal Health Single FalseSCO to generation mode Active Off Info Single TrueSCO to pump mode Active Normal Info Single TrueSequence starting Auto Manual Info Single FalseStator voltage Info Analogue Log_only NoUnder-frequency start Armed Off Health Single FalseGenerating Unit AGC – high limit

High Normal Health Single False

Generating Unit AGC – high regulating limit

Health Analogue Panel No

Generating Unit AGC – low limit

Low Normal Health Single False

Generating Unit AGC – low regulating limit

Health Analogue False

Generating Unit AGC – raise/lower blocking

Off Normal Info Single False

Generating Unit AGC – ramp rate

Info Analogue False

Generating Unit AGC – set-point active power

Info Analogue True

Generating Unit AGC – status On Off Info Single FalseGenerating Unit at standstill Yes Normal Info Single TrueGenerating Unit voltage Info Analogue FalseGenerating Unit guide vane Info Analogue TrueGenerating Unit in generation mode


Generating Unit in pump mode



Generating Unit in SCO mode Yes No Info Single TrueGenerating Unit load limiter Info Analogue TrueGenerating Unit reactive power generated

Info Analogue False


Info Analogue False


Info Analogue False


Info Analogue False

Generating Unit synchronising

Yes No Info Single False

Generating Unit turning in generation direction


Generating Unit turning in motor direction


(3) Steam units

Generating Unit Isolator 1 01_State 10_State Category Type ControlPole Disagree Normal Health Single FalseGenerating Unit isolator state Open Closed Info Double FalseGenerating Unit Isolator 2 01_State 10_State Category Type ControlPole Disagree Normal Health Single FalseGenerating Unit isolator state Open Closed Info Double FalseGenerating Unit HV Breaker


Breaker failed to trip Alarm Normal Main Single FalseBus zone trip Alarm Normal Info Single FalseEarth applied Alarm Normal Health Single FalsePole Disagree Normal Health Single FalseProtection abnormal Alarm Normal Health Single FalseProtection operated Alarm Normal Main Single FalseProtection unhealthy Alarm Normal Health Single FalseBreaker gas critical Alarm Normal Health Single False


Breaker non-urgent Alarm Normal Info Single FalseGenerating Unit breaker state Closed Tripped Info Double FalseCurrent Transformer 01_State 10_State Category Type ControlSF6 gas critical (CT) Alarm Normal Health Single FalseSF6 non-critical (CT) Alarm Normal Health Single FalseGenerating Unit Step Up Transformer


Reactive power Info Analogue FalseActive power Info Analogue FalseGenerating Unit LV Breaker 01_State 10_State Category Type ControlBreaker failed to trip Alarm Normal Main Single FalseEarth applied Alarm Normal Health Single FalsePole Disagree Normal Health Single FalseBreaker gas critical Alarm Normal Health Single FalseBreaker non-urgent Alarm Normal Info Single FalseGenerating Unit breaker state Closed Tripped Info Double FalseSteam Generating Unit 01_State 10_State Category Type ControlGenerating Unit AGC – high limit

High Normal Health Single False

Generating Unit AGC – high regulating limit


Generating Unit AGC – low limit

Low Normal Health Single False

Generating Unit AGC – low regulating limit


Generating Unit AGC – raise/lower blocking

Off Normal Info Single False

Generating Unit AGC – ramp rate

Info Analogue False

Generating Unit AGC – set-point active power

Info Analogue True

Generating Unit AGC – status On Off Info Single FalseGenerating Unit voltage Info Analogue FalseGenerating Unit islanded Alarm No Health Single FalseGenerating Unit reactive power generated

Info Analogue False


Info Analogue False


Info Analogue False


Info Analogue False

Generators contributing to Regulating Reserve shall provide indications for emergency generation and maximum generation for rescheduling.

2. Distributor and end-use customer

2.1 Transmission equipment

The Customer shall provide operational information for both real time and recording purposes in relation to each feeder, transformer and compensation device at each Substation required for the full functionality of a SVC, as well as full control by the System Operator.


2.2 Interruptible load

(1) All Interruptible loads shall meet the minimum requirements. The System Operator shall negotiate and integrate the conditions as presented in bilateral agreements and additionalcontractswithoutreducingtherequirementsasdefinedinthisGrid Code.

(2) The Interruptible Load shall install operationalmeasurements to specification soas to provide operational information for both real time and recording purposes in relation to each controllable energy block in respect of the following minimum requirements for operation and control of a Interruptible Load:

Isolator 01_State 10_State Category Type ControlPole Disagree Normal Health Single FalseIsolator state Closed Open Info Double FalseBreaker 01_State 10_State Category Type ControlGenerating Unit breaker state Closed Tripped Info Double TrueCurrent Transformer 01_State 10_State Category Type ControlSF6 gas critical (CT) Alarm Normal Health Single FalseSF6 non-critical (CT) Alarm Normal Health Single FalseLoad 01_State 10_State Category Type ControlLoad Reduction acknowledged No Yes Info Single TrueLoad interrupt acknowledged No Yes Info Single TrueBlock Load Reduction acknowledged

No Yes Info Single True

Return to service acknowledged No Yes Info Single TrueLoad active power Info Analogue False

(3) The availability of the Interruptible Load shall be integrated into the ancillary service schedules by the market operator before the transfer to the System Operator.


ANNEXURE 12

Market operational schedules

1. Energy market schedules

No Data entity Data description Format Size Unit1 Power Station The official abbreviation of the Power

Station name as defined by the System Operator.

Characters 5

2 Generating Unit The Generating Unitidentificationnumber. Integer 0 - 993 Hour Contract hour. Integer 1-24 Hour4 Contract The contracted generation output per

Generating Unit.Integer 0 - 999 MWh


Station name as defined by the System Operator.

Characters 5

2 Generating Unit The Generating Unitidentificationnumber. Integer 0 – 993 Min generation Minimum generation capability of

Generating UnitInteger 999 MW

4 Price 1 Real 999,99 R5 Minus elbow 16 Elbow 1 Integer 999 MW7 Price 2 Real 999,99 R8 Minus elbow 29 Elbow 2 Integer 999 MW10 Price 3 Real 999,99 R11 Price 4 Real 999,99 R12 Price 5 Real 999,99 R13 Price 6 Real 999,99 R14 Max generation Integer 999 MW

2. Ancillary services market schedules


Station name as defined by the System Operator

Characters 5

2 Generating Unit The Generating Unitidentificationnumber Integer 0 – 993 Hour Contract hour Integer 1-24 H o u r

(h)4 Spinning Reserve Spinning Reserve contract Integer 0 – 999 MW5 Flexibility Boolean ‘F’/’I’6 AGC Flag for being contracted for AGC either up

or downBoolean ‘Y’/’N’

7 AGC up Regulation contracted up Integer 0 – 99 MW8 AGC down Regulation contracted down Integer 0 – 99 MW9 Quick Reserve Quick Reserve contract Integer 0 – 99 MW10 Demand-side

Quick ReserveReserve available from Quick Reserve demand-side resources

Integer 0 – 99 MW

11 Supply-side Quick Reserve

Reserve available for Quick Reserve from supply-side resources

Integer 0 – 99 MW


ANNEXURE 13

Post-dispatch information

(1) The System Operator shall provide the following minimum operational information in near real-time and as historic data in relation to each Generating Unit at each Power Station:

No Data entity Data description Format Size Unit1 Generating Unit high

limitReal 999,99 MW

2 Generating Unit low limit Real 999,99 MW3 Generating Unit AGC

modeCER/BLO Character 3

4 Generating Unit AGC status

AUT/OFF/MAN Character 3

5 Generating Unit set-point Real 99,99 MW6 AGC pulse Real 9,97 Generating Unit sent-out Real 999,99 MW8 Generating Unit auxiliary Real 999,99 MW9 Generating Unit contract Integer 999 MW10 Generating Unit spinning Integer 99911 AGCflag 32-bitflagonAGC

settingsInteger 32 bits

(2) If Namibia is a control area then the System Operator shall provide the following minimum operational information in near real-time in relation to the overall dispatch performance:

No Data entity

Data description Format Size Unit

1 ACE Area Control Error Real 999,99 MW2 Average ACE previous hour Real 999,99 MW3 HZ System frequency Real 99,999 MW4 Frequency distribution current hour Real 999,99 MW5 Frequency distribution previous hour Real 999,99 MW6 System total generation Integer 99999 MW7 Control area total actual interchange Integer 99999 MW8 Control area total scheduled interchange Integer 99999 MW9 System operating reserve Integer 99999 MW10 System sent-out Integer 99999 MW11 System Spinning Reserve Integer 99999 MW12 AGC regulating up Integer 99999 MW13 AGC regulating down Integer 99999 MW14 AGC regulating up assist Integer 99999 MW15 AGC regulating down assist Integer 99999 MW16 AGC regulating up emergency Integer 99999 MW17 AGC regulating down emergency Integer 99999 MW18 AGC mode Char TLBC /CFC19 AGC status Char ON/ OFF20 Area Control Error output Real 999.99 MW21 System Transmission Losses Real 999.99 MW22 South Africa tie-lines Integer 99999 MW23 AGC performance indicators


ANNEXURE 14

GENERATOR PERFORMANCE DATA

1. Measurement of Availability

(1) The Unipede/Eurelectric standard for the measurement of plant availability must be used. Availability is measured with the use of an indicator known as “energy availability factor” (EAF).

(2) EAF represents the network point-of-view.

(3) The “energy availability factor” has the same conceptual content as the “equivalent availability factor” used by USA operators, for example the NERC-GADS data bank.

(4) Energyavailabilityfactorisdefinedastheratiooftheavailableenergygeneration(b) over a given time period (PH) to the reference energy generation over the same period, expressed as a percentage. Both of these energy generation terms are determined relative to reference ambient conditions.

(5) Available energy generation (b) for the purpose of calculating EAF is the energy that could have been produced under reference ambient conditions considering limitations within and beyond the control of the plant management.

(6) Reference energy generation (Y) is the energy that could be produced during a given time period if the Generating Unit were operated continuously at reference Generating Unit power (PM) under reference ambient conditions throughout the period.

(7) Reference ambient conditions are environmental conditions representative of the annual mean (or typical) ambient conditions for the Generating Unit.

(8) Alternativedefinition:The“energyavailabilityfactor”(f),overaspecifiedperiod,is the ratio of energy (b) that the available capacity (Pd) could have produced during this period to the energy (Y) that the net maximum electrical capacity (PM) could have produced during the same period.

(9) The energy produced (b) (or capable of being produced) by the available capacity (Pd) may also be calculated as the difference between the energy (Y) (the maximum electrical capacity –PM – that could have been produced) and the unavailable energy (c) (which was not produced or not able to be produced) by the total unavailable capacity (Pit).

(10) Note: For the NamPower reporting systems c is calculated from a summation of unavailable MWh due to outages and restrictions (planned, unplanned, external and non-engineering) occurring throughout the period from MW capacity loss x duration (hr) of the loss.


2. Components of the energy availability factor (EAF) (GCR1.1)

(1) Unplanned capability loss factor (UCLF) (GCR1.2)

The purpose of this indicator is to monitor industry progress in minimising outage time and power reductions that result from unplanned equipment failures or other conditions. This indicator reflects the effectiveness of plant programmes andpractices in maintaining systems available for safe electrical generation.

(2) Other capability loss factor (OCLF) (GCR 1.3)

Other capability loss factor is an indicator to monitor outage time and power reductions due to causes beyond the control of plant management.

(3) Planned capability loss factor (PCLF) (GCR1.4)

PlannedcapabilitylossfactorisdefinedastheratiooftheplannedenergyLosses during a given period of time to the reference energy generation expressed as a percentage.

Planned energy loss is energy that was not produced during the period because of planned shutdowns or Load Reductions due to causes under plant management control. Energy Losses are considered to be planned if they are scheduled at least four weeks in advance.

(4) Generating unit capability factor (UCF)

Note: UCF represents the GENERATOR’S POINT OF VIEW

The purpose of this indicator is to monitor progress in attaining high Generating Unit andindustryenergyproductionavailability.Thisindicatorreflectseffectivenessofplant programmes and practices in maximising available electrical generation and provides an overall indication of how well plants are operated and maintained.

3. Measurement of availability reliability

(1) The Unipede/Eurelectric standard for the measurement of plant reliability must be used.

(2) Reliabilityismeasuredwiththeuseoftwospecificindicators,namelyunplannedautomatic grid separations (UAGS) and successful start-up rate.

4. Unplanned automatic grid separations per 7 000 operating hours (UAGS/7000h)

(1) The purpose of this indicator is to enable monitoring of an important aspect of the reliability of service supplied to the electrical grid. It takes into account success in improving reliability by reducing the number of turbo generator trips. It also provides an indication of plant operation and maintenance performance.

(2) Taking account of the number of operating hours when the turbo generator set is connected to the electrical grid enables assessment of required reserves. Furthermore, using a common standard for all grid separation data for each Generating Unit provides a uniform basis for comparison among units with values for the industry as a whole.


(3) Intentional (manual) grid separations are not taken into account since operators should not be discouraged from taking action to protect equipment.

(4) This indicator may be defined as corresponding to the number of unplanned(unintentional) automatic grid separations of internal origin that occur per 7 000 operatinghours.Thisdefinitioncanbeclarifiedasfollows:

(5) “Unplanned” means that grid separation is not an anticipated part of a planned test, nor part of an operating programme designed to adjust output to demand (e.g. a controlled shutdown). Controlled shutdowns of units where the line circuit breaker ismanuallyorautomaticallyopenedatloadsequaltoorbelowthefirstautomaticsynchronising load should not be considered when computing this indicator.

(6) “Grid separation” means the opening of the generator breaker or HV yard breaker where no generator breaker exists. This could be an opening signal actuated by overshooting of a safety threshold, or a spurious trip. Grid separation can only occur during grid service of the units. Grid service is obtained when the start-up is successfulforrequestedstart-upsorwhenloadsinexcessofthefirstsynchronisingload are reached for “contracted” or “other start-ups” (i.e. house or block load as programmed into the automatic synchronising equipment).

(7) “Automatic” (unintentional) means that the grid separation is not the result of an action by the operator either on one of the switches to trigger a Generating Unit trip or grid separation or to simulate operation of a Protection system.

(8) Trips caused by the operator in error, e.g. opening the wrong switch leading to a trip, are excluded from the “manual” category. Controlled shutdowns of units where the line circuit breaker is manually or automatically opened at loads equal to or below thefirstautomaticsynchronisingloadshouldnotbeconsideredwhencomputingthisindicator.

(9) “Operating” means that the turbo generator set is connected to the off-site grid (Transmission of generated power) even if the alternator is operating in synchronous motor mode owing to exceptional circumstances.

(10) “Ofinternalorigin”meansthatthetripisduetoanunspecifiedinternalinstallationfailure resulting in a loss of reliability – even if the initial event can be traced to an off-site cause. The signal that triggered grid separation must originate from one of the sensors (or Protection logic) for monitoring Generating Unit parameters (turbo generator set and power Transmission, up to and including the generator transformer HV breaker, and boiler). Grid separations actuated by Protection systems for the physical parameters of the grid are not included unless they were incorrectly controlled.

(11) Theselectedfigureof7000hoursrepresentsthetypicalnumberofon-linehoursformost plants operating at base load or semi-base load. The indicator thus represents an approximate value of the actual number of grid separations occurring in one year.

(12) The following data are required to determine the value for this indicator -

(a) the number of unplanned automatic grid separations (U) with the generator circuit breaker (or HV breaker where no generator breaker exists) in initially closed position; and

(b) the number of operating hours (OPH).


(13) All automatic trips are counted for the UAGS indicator, including those auto trips occurring within +30 minutes of all requested start-ups that comply with the ±15-minute time limit for synchronization.

(14) Data for new units is included in the calculation of industry values beginning January 1ofthefirstcalendaryearfollowingthestartofcommercialoperation.However,in order to be included in the industry value, the Generating Unit must have at least 1 000 operating hours per year. This minimum operating period requirement reduces the effects of plants that are shut down for long periods of time and for which limited data may not be statistically valid.

(15) SummariseddefinitionofUAGS per 7 000 hours: This indicator tracks the average grid separation rate per 7 000 operating hours (approximately one year of operation) for units having at least 1 000 operating hours during the year. Only trips of internal origin to the installation are included and trips for the physical parameters of the grid are not included unless they were incorrectly controlled.

5. Successful Start-up Rate (GCR2.2)

(1) The “successful start-up rate” is the ratio of the number of successful start-ups to the number of contracted start-ups over a given period of time. It measures the reliability of the service that is rendered to the customers.

(2) Start-up comprises the set of operations that enable the Generating Unit to be connected to the off-site power grid for the production of electrical energy according to requirements issued by the grid administrator. Connection of the Generating Unit tothegrid(closingthelinecircuitbreaker)isthepurposeofthefirststart-upphase,before loading and stabilisation at the required power level. Only this initial start-up phase, the success of which results in sustained grid connection, is considered here.

(3) The contracted start-up refers to an agreement between the grid administrator (through any medium, i.e. verbally, telephonically, etc.) and the station, following a request from the grid administrator or the station. This forms part of a grid management schedule (hereafter referred to as the ‘real’ National Control programme) for the full range of power generation resources (excluding tests). The request for a start-up in advance of the synchronising time corresponds to the technical delay due to equipment start-up times. This delay time can be reduced to almost zero in the case of start-up of peak-supply gas turbines with centralised, automatic control systems. For any given start-up contract, a precise time for grid connection and an implementation schedule are required (except for peak-load gas turbines). In theeventofasuddenmodificationbythegridadministratorofthegridconnectioncontract time, within the start-up capabilities of the Generating Unit, a new contract needs to be entered into.

(4) The following indicators are still under development:

(a) protection management;

(b) ability to island;


(c) excitation system management;

(d) reactive capabilities;

(e) multiple-generating unit trip risks;

(f) governing requirements;

(g) restart after station blackout capability;

(h) black start capability;

(i) intermediate load capability;

(j) external supply disturbance withstand capability;

(k) loading rates; and

(l) on-load tap changing for generating set-up transformers.


ANNEXURE 15

Planning schedules

Schedule 1: Ten-year demand forecast

Demand = Total Demand + Distribution Losses – Embedded GenerationMaximum demand Expected minimum de-

mand Year GWh MW MVAr MW MVArMeasured (year 0)Year 1Year 2Year 3Year 4Year 5Year 6Year 7Year 8Year 9Year 10


Sche

dule

2:

Em

bedd

ed g

ener

atio

n >

500k

VAG

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ator

Tx

Subs

tatio

n na

me

at

clos

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ctio

n po

int

Ope

ratin

g po

wer

fact

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capa

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Plan

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s-ag

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et s

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atio

n ne

t sen

t out

con

trib

utio

n at

pea

k

(MW

)

Normal

Peak

Normal

Peak

Year 1

Year 2

Year 3

Year 4

Year 5

Year 6

Year 7

Year 8

Year 9


ANNEXURE 16

INFORMATION RELATING TO DETAILS SPECIFIED

No. Detail Specification1. Commissioning Projected or target commissioning test date2. Operating Target operational or on-line date3. Reliability of connection requested Numberofconnectingcircuitse.g.oneortwofeeders,orfirm/

non-firm supply required (subject to Network and Tariff Code requirements)

4. Location map. Upgrades: Name of existing Point of Supply to be upgraded and supply voltage.New connections: Provide a 1:50 000 or other agreed scale location map, with the location of the facility clearly marked. In addition, please specify the co-ordinates of the Point of Connection.

5. Site plan Provide a plan of the site (1:200 or 1:500) of the proposed facility, with the proposed Point of Supply, and where applicable, the Transmission line route from the facility boundary to the Point of Supply, clearly marked.

6. Electrical single-line diagram Provide an electrical single-line diagram of the customer intake Substation.

ANNEXURE 17

MEASUREMENT EQUIPMENT ACCURACY CLASSES

Measurement equipment Accuracy classCurrent transformer (CT) 0,2%Voltage transformer (VT) 0,2%Transducer 0,2%Analogue to digital conversion, i.e. RTU 0,01%

ANNEXURE 18

DAILY 24 HOURS DAY-AHEAD ENERGY SCHEDULE

File Description Trigger event FrequencyDispatch schedule

The combined 24-hour day-ahead energy and ancillary services schedules. Hourly day-ahead contracts for different market categories that identify the Generating Unit with the next 24 hourly values for it.

Generation dispatch schedule

Daily

Daily price curve

Daily price curve with incremental prices and corresponding volumes.

Generation dispatch schedule

Daily


ANNEXURE 19

File Description Trigger Event FrequencyAGC pulses The total pulses sent to a Generating Unit by

the AGC system to move the set point up or down

Ongoing,filecreatedatend of hour

Hourly

NERC A list of the total NERC “A1” and “A2” criteria violations in the system over an hour

Ongoing, file appendedat end of hour

Daily

System near real-time data

Historic near real-time system data files onreadings as required for post-dispatch

Communication failure To be agreed

Generating Unit near real-time data

Historic near real-time Generating Unit data filesonreadingsasrequiredforpost-dispatch

Communication failure To be agreed

ANNEXURE 20

Distributor :Date:Substation:Fed from Transmission Substation (directly or indirectly):

Activating frequency Timer settingRequired As tested Required As tested

Stage 1Stage 2Stage 3Stage 4

Feeders selected (Required) Feeders selected (As tested)Stage 1Stage 2Stage 3Stage 4

ANNEXURE 21

Indicator Month Year to date 12 MMI UnitSystem Minutes lost minutesNo. of InterruptionsNo. of statutory voltage transgressionsMandatory under-frequency load sheddingCustomer voluntary load sheddingTransmission system Losses %


ANNEXURE 22

Thevaluesoff0,f1,f2,f3,k1,k2,andk3mustbesettableforthespecificnetworklocationandapplicable conditions. The range of values for k1 and k2 are automatically determined by the range of values given above for f0, f1, f2, and f3.

ANNEXURE 23


ANNEXURE 24


ANNEXURE 25

Total Harmonic planning levels

Harmonicorder Harmonic voltage %

MV (up to HV/EHV (above h 33kV) 33kV) 2 1.6 1.5 3 4 2 4 1 1 5 5 2 6 0.5 0.5 7 4 2 8 0.4 0.4 9 1.5 1.5 10 0.4 0.4 11 3 1.5 12 0.2 0.2 13 2.5 1.5 14 0.2 0.2 15 0.3 0.3 16 0.2 0.2 17 1.6 1 18 0.2 0.2 19 1.2 1 20 0.2 0.2 21 0.2 0.2 22 0.2 0.2 23 1.2 0.7 24 0.2 0.2 25 1.2 0.7 >25 0.2 + 0.5*25/h 0.2 + 0.5*25/hInter-harmonics 0.2 0.2THD <6.5 <3

________________